User manual | EPRI Feasibility Study for an Integrated Gasification Combined Cycle Facility at a Texas Site

Feasibility Study for an Integrated Gasification

Combined Cycle Facility at a Texas Site

1014510

Feasibility Study for an Integrated

Gasification Combined Cycle

Facility at a Texas Site

1014510

Technical Update, October 2006

Cosponsor

CPS Energy

145 Navarro

San Antonio, TX 78296

Project Manager

J. Kosub

EPRI Project Manager

G. Booras

ELECTRIC POWER RESEARCH INSTITUTE

3420 Hillview Avenue, Palo Alto, California 94304-1338

▪ PO Box 10412, Palo Alto, California 94303-0813 ▪ USA

800.313.3774

▪ 650.855.2121 ▪ [email protected] ▪ www.epri.com

DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES

THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS AN

ACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCH

INSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THE

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PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT.

ORGANIZATION(S) THAT PREPARED THIS DOCUMENT

Burns & McDonnell Engineering Co. Inc.

This is an EPRI Technical Update report. A Technical Update report is intended as an informal report of continuing research, a meeting, or a topical study. It is not a final EPRI technical report.

NOTE

For further information about EPRI, call the EPRI Customer Assistance Center at 800.313.3774 or e-mail [email protected]

Electric Power Research Institute and EPRI are registered service marks of the Electric Power

Research Institute, Inc.

CITATIONS

This report was prepared by

Burns & McDonnell

9400 Ward Parkway

Kansas City, MO 64114

Principal Investigator

J. Schwarz

This report describes research sponsored by the Electric Power Research Institute (EPRI) and

CPS Energy.

This publication is a corporate document that should be cited in the literature in the following manner:

Feasibility Study for an Integrated Gasification Combined Cycle Facility at a Texas Site. EPRI,

Palo Alto, CA: 2006. 1014510. iii

PRODUCT DESCRIPTION

Interest in integrated gasification combined cycle technology (IGCC) has grown sharply since the passage of the Energy Policy Act in 2005. Many new projects are being planned since the

AEP and Duke 600 MW IGCC plants were announced nearly two years ago. This report compares the cost and performance of IGCC with a supercritical pulverized coal plant (SCPC) based on lower rank PRB coal. The IGCC options included 100% PRB and 50/50 PRB/petcoke cases. The addition of CO

capture equipment was also evaluated as a retrofit for the 100% PRB

IGCC and SCPC facilities.

Results and Findings

The net plant heat rates for the IGCC and SCPC plants without CO

capture are similar, with the

100% PRB IGCC case having a slightly worse heat rate while the PRB/petcoke blend IGCC case has a slightly better heat rate than the PRB-fired SCPC. IGCC has an advantage in terms of SO

, and mercury emissions, with NO x

emissions being similar for both technologies. SCR was not included for the IGCC unit due to concerns that ammonium bisulfate (ABS) deposits could plug the finned heat transfer surfaces of the HRSG downstream of the SCR. In addition, IGCC technology consumes less water than SCPC technology.

The capital costs for the IGCC cases are approximately 20% higher than the cost for the SCPC case. There is about a 2.5% capital cost savings for the 50/50 PRB/petcoke IGCC over the 100%

PRB IGCC due to the higher heating value of the blended fuel (lower water and ash contents).

The 100% PRB SCPC unit has the lowest busbar cost of all alternatives.

The installation of CO

capture equipment as a retrofit for both of these technologies results in a very significant decrease in plant output. The IGCC net plant output decreases by approximately

25% and the SCPC decrease in output is 29%. Likewise, the net plant heat rate of the facilities also increases by approximately 39% for the IGCC and 41% for the SCPC. Water consumption is also increased by approximately 23% for IGCC and 34% for SCPC.

All of these factors result in an increase of the levelized busbar cost by approximately 45% for the IGCC and 58% for the SCPC post CO

capture. SCPC technology still provides the lowest busbar cost after CO

capture retrofit, although by less of a gap than pre-CO

capture. The avoided cost of CO

capture is less for an IGCC implying that IGCC technology is the more economical choice for retrofit of CO

capture technology.

Challenges and Objectives

The Shell gasification process chosen for this application utilizes a dry-feed system, which has advantages over slurry-feed gasification processes for low rank coal (for the non-CO

capture case). However, the Shell gasification process produces syngas with higher concentrations of

CO and less H

than would be produced by a slurry-feed gasifier. When adding CO

capture v

equipment to the Shell gasification process, more steam is required to convert the CO to CO

and

2 than would be required for a slurry-feed gasifier. This results in less steam available to the steam turbine, which equates to less plant output for the CO

capture case than may be seen if using a slurry-feed gasifier. If the objective of the Owner is to capture CO

, then a slurry-feed gasifier may be a better choice than a dry-feed gasifier. Another option would be a water quench version of the Shell gasifier, which would require some additional development.

Applications, Values, and Use

In recent years, several factors have caused the cost of power projects to increase at a higher rate than in years past. The world demand for many commodities has increased sharply, resulted in a

100-300% cost increase for some commodities including steel (in particular stainless or high alloy steel), concrete, copper, oil, and nickel. The compounding effect of labor productivity, high labor rate escalation, commodity cost escalation, risk mitigation, and contractor markups results in much higher project costs for both IGCC and SCPC than may have been anticipated one or two years ago. It is important that owners who are planning to add new generation have access to the most recent cost and performance estimates.

EPRI Perspective

This is the first EPRI study performed that evaluates CO

capture as a retrofit to existing IGCC and SCPC units. Other EPRI studies have evaluated CO

capture on new units specifically designed for and incorporating CO

capture from the start. Additionally, this is the first detailed study performed by EPRI that evaluates IGCC and PC technology with CO

capture when using a lower rank, higher moisture PRB coal. Other detailed studies performed by EPRI focused primarily on higher rank bituminous coals (using slurry-fed gasifiers), where IGCC has been shown to provide a more distinct advantage.

Approach

Burns & McDonnell was engaged by CPS Energy and EPRI to perform a feasibility study for a nominal 550 MW (net) IGCC facility to be located at a greenfield Texas Gulf Coast location.

The IGCC options were based on the use of Shell coal gasification technology with GE 7FB gas turbines. EPRI’s in-house computer model was used to estimate the performance of the Shell coal gasification process for both fuels. UOP’s SELEXOL system was used as the basis for the

IGCC CO

capture technology and Fluor’s Econamine FG Plus

system was used for SCPC CO

2 capture technology. This report provides screening level capital cost, performance, operations and maintenance costs, availability factors, and emission rates for the two IGCC alternatives.

The capital costs include many site and owner-specific items that are not normally included in

EPRI’s Technical Assessment Guide (TAG

Keywords

Integrated Gasification Combined Cycle

Pulverized Coal

Capture

PRB Coal vi

1 EXECUTIVE SUMMARY ........................................................................................................1-1

Overview ...............................................................................................................................1-1

IGCC Options ........................................................................................................................1-1

Deliverables...........................................................................................................................1-2

Results ..................................................................................................................................1-2

Current Market Conditions ....................................................................................................1-6

Limitations and Qualifications................................................................................................1-7

2 INTRODUCTION ....................................................................................................................2-1

Background ...........................................................................................................................2-1

Objectives .............................................................................................................................2-1

Status of the Technology.......................................................................................................2-2

Selection of Gasification Technology ....................................................................................2-2

Project Experience ................................................................................................................2-3

Fuel experience.....................................................................................................................2-4

Technical Approach and Data Sources.................................................................................2-4

3 STUDY CRITERIA ..................................................................................................................3-1

Site Selection ........................................................................................................................3-1

Gas Turbine Selection...........................................................................................................3-1

Fuel Selection .......................................................................................................................3-1

Plant Capacity Selection .......................................................................................................3-3

Capacity Factor and Availability Factor Targets....................................................................3-4

4 PROCESS DESCRIPTION .....................................................................................................4-1

Gasification System Description............................................................................................4-1

Air Separation Unit (ASU).................................................................................................4-1

Gasifiers ...........................................................................................................................4-4

vii

Gasifier Performance Estimate by EPRI......................................................................4-5

Slag Handling ...................................................................................................................4-6

Fly Ash System.................................................................................................................4-7

Syngas Wash Towers.......................................................................................................4-7

COS / HCN Hydrolysis .....................................................................................................4-8

Syngas Cooling and Condensation ..................................................................................4-9

Mercury Removal ...........................................................................................................4-10

Acid Gas Removal (AGR)...............................................................................................4-10

Sulfur Recovery and Tail Gas Treating ..........................................................................4-13

Sulfur Recovery Units (SRU) .....................................................................................4-13

Tail Gas Treating Unit (TGTU)...................................................................................4-15

Tail Gas Compression ...............................................................................................4-16

Thermal Oxidizer........................................................................................................4-16

Sour Water Stripping ......................................................................................................4-16

Syngas Saturation ..........................................................................................................4-17

Power Block Description .....................................................................................................4-17

Gas Turbines ..................................................................................................................4-17

Heat Recovery Steam Generators (HRSG)....................................................................4-18

Steam Turbine ................................................................................................................4-18

Steam Condenser...........................................................................................................4-19

Steam System ................................................................................................................4-19

Condensate System .......................................................................................................4-19

Feedwater System..........................................................................................................4-19

Natural Gas System .......................................................................................................4-19

Balance of Plant ..................................................................................................................4-20

Coal Handling .................................................................................................................4-20

100% PRB Option......................................................................................................4-20

50% PRB / 50% Petcoke Option................................................................................4-20

Cooling System ..............................................................................................................4-20

Auxiliary Boiler................................................................................................................4-21

Buildings .........................................................................................................................4-21

Water Treatment.............................................................................................................4-21

Raw Water/Service Water..........................................................................................4-22

Demineralized Water .................................................................................................4-23

viii

Wastewater ................................................................................................................4-23

Sanitary Drains ..........................................................................................................4-23

Flare ...............................................................................................................................4-23

Fire Protection ................................................................................................................4-23

Plant Drains ....................................................................................................................4-24

Electrical Systems ..........................................................................................................4-24

Auxiliary Power Supply ..............................................................................................4-24

Generator and Excitation ...........................................................................................4-25

Switchyard .................................................................................................................4-25

Essential AC and DC Power Supply ..........................................................................4-26

Freeze Protection ......................................................................................................4-26

5 TERMINAL POINTS ...............................................................................................................5-1

General .................................................................................................................................5-1

Site Access ...........................................................................................................................5-1

Rail Siding .............................................................................................................................5-1

Sanitary Waste ......................................................................................................................5-1

Natural Gas ...........................................................................................................................5-1

Raw Water Supply.................................................................................................................5-1

Wastewater Discharge ..........................................................................................................5-2

Electrical Interface.................................................................................................................5-2

6 IGCC PERFORMANCE ESTIMATES ....................................................................................6-1

Performance Estimate Assumptions .....................................................................................6-1

Performance Estimate Results..............................................................................................6-1

7 IGCC CAPITAL COST ESTIMATES ......................................................................................7-1

Capital Cost Estimate Assumptions ......................................................................................7-1

Indirect Construction Costs (Included in EPC Cost)..............................................................7-2

Owner Indirect Costs.............................................................................................................7-3

Costs not included.................................................................................................................7-4

Capital Cost Results..............................................................................................................7-4

8 IGCC OPERATIONS AND MAINTENANCE ..........................................................................8-1

O&M Assumptions.................................................................................................................8-1

O&M Exclusions ....................................................................................................................8-2

O&M Results .........................................................................................................................8-2

9 IGCC AVAILABILITY .............................................................................................................9-1

General .................................................................................................................................9-1

Assumptions and Clarifications .............................................................................................9-1

Availability Factor ..................................................................................................................9-1

10 IGCC EMISSIONS ESTIMATES ........................................................................................10-1

General ...............................................................................................................................10-1

11 SUPERCRITICAL PC ESTIMATES ...................................................................................11-1

General ...............................................................................................................................11-1

SCPC Capital Cost Assumptions ........................................................................................11-1

SCPC Capital Cost Results.................................................................................................11-2

SCPC Performance Assumptions .......................................................................................11-4

SCPC Performance Estimate Results.................................................................................11-4

SCPC O&M Cost Assumptions ...........................................................................................11-5

SCPC O&M Exclusions .......................................................................................................11-5

SCPC O&M Results ............................................................................................................11-5

SCPC Emission Rates ........................................................................................................11-6

Availability Factor ................................................................................................................11-8

12 ECONOMIC ANALYSIS .....................................................................................................12-1

General ...............................................................................................................................12-1

Assumptions........................................................................................................................12-1

Economic Analysis ..............................................................................................................12-3

Sensitivity Analysis..............................................................................................................12-5

13 CO

CAPTURE ...................................................................................................................13-1

General ...............................................................................................................................13-1

IGCC CO

Capture ..............................................................................................................13-3

IGCC Modifications for CO

Capture ..............................................................................13-4

Sour Shift ...................................................................................................................13-4

Syngas Cooling and Condensation............................................................................13-5

Acid Gas Removal (AGR) ..........................................................................................13-5

IGCC Impacts from CO

Capture....................................................................................13-5

IGCC Performance – CO

Capture ............................................................................13-5

IGCC Capital Cost – CO

Capture .............................................................................13-7

IGCC Operations and Maintenance – CO

Capture...................................................13-7

IGCC Emissions – CO

Capture ................................................................................13-9

IGCC Pre-Investment Options for CO

Capture.......................................................13-10

SCPC CO

Capture ...........................................................................................................13-10

SCPC Modifications for CO

Capture ...........................................................................13-12

SCPC Impacts from CO

Capture.................................................................................13-13

SCPC Performance – CO

Capture .........................................................................13-13

SCPC Capital Cost – CO

Capture ..........................................................................13-14

SCPC Operations and Maintenance – CO

Capture................................................13-15

SCPC Emissions – CO

Capture .............................................................................13-17

SCPC Pre-Investment Options for CO

Capture......................................................13-17

Capture Economics....................................................................................................13-18

14 OTHER CONSIDERATIONS ..............................................................................................14-1

Byproduct Sales ..................................................................................................................14-1

Co-Production .....................................................................................................................14-1

Plant Degradation................................................................................................................14-2

Lignite Gasification ..............................................................................................................14-2

15 SUMMARY .........................................................................................................................15-1

A PROCESS FLOW DIAGRAMS............................................................................................. A-1

B SITE LAYOUT DRAWINGS.................................................................................................. B-1

C WATER MASS BALANCE DIAGRAMS............................................................................... C-1

D ELECTRICAL ONE-LINE DIAGRAMS ................................................................................. D-1

E CAPITAL COST DETAIL ...................................................................................................... E-1

F HEAT BALANCE DIAGRAMS ...............................................................................................F-1

G O&M COST DETAIL ............................................................................................................. G-1

H SYSTEM OF INTERNATIONAL UNITS CONVERSION TABLE ......................................... H-1

LIST OF FIGURES

Figure 4-1 Gasification Block Flow Diagram ..............................................................................4-1

Figure 4-2 Generic ASU Process Flow Diagram .......................................................................4-4

Figure 4-3 SELEXOL Process Flow Diagram ..........................................................................4-12

Figure 4-4 Block Flow Diagram – Sulfur Recovery and Tail Gas Treating...............................4-13

Figure 12-1 20-Year Levelized Busbar Cost (2006 US Dollars) ..............................................12-3

Figure 12-2 Breakout of 20-Year Levelized Busbar Cost (2006 US Dollars) ...........................12-4

Figure 12-3 Sensitivity Analysis – SCPC Unit – 100% PRB Coal............................................12-5

Figure 12-4 Sensitivity Analysis – IGCC – 50% PRB Coal / 50% Petcoke ..............................12-6

Figure 12-5 Sensitivity Analysis – IGCC – 100% PRB Coal ....................................................12-6

Figure 13-1 CO

Storage Supply Curve for North America ......................................................13-3

Figure 13-2 Fluor EFG+ Block Flow Diagram ........................................................................13-11

Figure 14-1 Products from Syngas ..........................................................................................14-2

Error! No table of figures entries found xiii

LIST OF TABLES

Table 1-1 Executive Summary Table (Table 1 of 2) ..................................................................1-3

Table 1-2 Executive Summary Table (Table 2 of 2) ..................................................................1-4

Table 2-1 IGCC Facilities – Past and Current............................................................................2-4

Table 3-1 Fuel Analyses ............................................................................................................3-3

Table 4-1 ASU Material Balances..............................................................................................4-3

Table 4-2 Summary of Gasifier Modeling Results .....................................................................4-6

Table 4-3 Assumed Raw Water Quality..................................................................................4-22

Table 6-1 IGCC Performance Summary ....................................................................................6-2

Table 7-1 IGCC Capital Cost Estimate Summary (2006 US Dollars) ........................................7-5

Table 8-1 IGCC O&M Summary (2006 US Dollars)...................................................................8-3

Table 10-1 IGCC Target Emission Rates ................................................................................10-2

Table 11-1 550 MW (Net) SCPC Capital Cost Estimate Summary (2006 US Dollars) ............11-3

Table 11-2 550 MW (Net) SCPC Performance Summary........................................................11-4

Table 11-3 550 MW (Net) SCPC O&M Summary (2006 US Dollars) ......................................11-6

Table 11-4 500 MW (Net) SCPC Emissions Estimates ...........................................................11-8

Table 13-1 CO

Purity Specification.........................................................................................13-2

Table 13-2 IGCC Performance Impacts from CO

Capture .....................................................13-6

Table 13-3 IGCC Capital Cost Additions for CO

Capture Retrofit...........................................13-7

Table 13-4 IGCC O&M Impacts from CO

Capture..................................................................13-8

Table 13-5 IGCC Emissions Impacts from CO

Capture .........................................................13-9

Table 13-6 SCPC Performance Impacts from CO

Capture ..................................................13-14

Table 13-7 SCPC Capital Cost Additions for CO

Capture Retrofit........................................13-15

Table 13-8 SCPC O&M Impacts from CO

Capture...............................................................13-16

Table 13-9 SCPC Emissions Impacts from CO

Capture ......................................................13-17

Table 13-10 CO2 Capture Busbar Costs ...............................................................................13-18

Table 15-1 Summary Table (1 of 2) .........................................................................................15-2

Table 15-2 Summary Table (2 of 2) .........................................................................................15-3

ACRONYMS, ABBREVIATIONS, AND SYMBOLS

6 million

$/MMBtu dollars per million British thermal unit

ALPC Air Liquide Process and Construction

Btu/kWh

British unit

British thermal unit(s) per kilowatt-hour

DCS distributed control system

Plus

(Fluor CO

capture system)

EPRI Electric Power Research Institute

generator (transformer)

gas generator

hydrogen xvii

HRSG

HVAC

higher value heat recovery steam generator heating, ventilation, and air conditioning

lower value

LTGC

LTSA low temperature gas cooling long term service agreement

low

3 m cubic meters

motor center

nitrogen

Air Standards

NFPA National Fire Protection Association

ammonia

NO x nitrous oxide ppmv ppmvd

power module ppmvd @ 15% O

2 part(s) per million by volume part(s) per million by volume (dry) part(s) per million by volume (dry) corrected to 15% oxygen

steam generator xviii

TGTU tail gas treatment unit xix

CERTIFICATION PAGE

Electric Power Research Institute & CPS Energy

Feasibility Study for an Integrated Combined Cycle Facility at a Texas Site

DOCUMENT DESCRIPTION

Report/Appendices Findings of IGCC Feasibility Study

CERTIFICATION(S)

NUMBER

221 xxi

EXECUTIVE SUMMARY

Overview

Integrated gasification combined cycle (IGCC) technology has been the source of much interest in the world of advanced coal-fired generation. IGCC technology provides a bridge between the two mature technologies of coal gasification and combined cycle technology by producing a medium-Btu value syngas from coal or other solid fuel and firing it in a modified conventional gas turbine as part of a combined cycle application.

Burns & McDonnell was engaged by CPS Energy (Owner) and EPRI to perform a feasibility study for IGCC technology to be located at a greenfield Texas Gulf Coast location.

IGCC Options

Due to the availability of petroleum coke (petcoke) and PRB coal in the area, two IGCC options were evaluated:

Option 1 – 100% PRB

Option 2 – 50% PRB / 50% Petcoke (% by weight)

For this evaluation, a 2x1 (two gas turbine/HRSG trains and 1 steam turbine) configuration was selected. The IGCC facility consists of the following major equipment:

• 1 high-pressure air separation unit (ASU) with 2x50% main air compressors and nitrogen compressors, utilizing a portion of air extracted from the gas turbine compressors at lower ambient temperatures (air-side integration).

• 2 Shell gasifiers.

• 1 SELEXOL

acid gas removal (AGR) system.

• 2 sulfur recovery units (SRU).

• 1 tail gas treating unit (TGTU).

• 2 General Electric (GE) 7FB gas turbine generators (GTG).

1-1

Executive Summary

• 2 heat recovery steam generators (HRSG).

• 1 steam turbine generator (STG).

• Balance of plant (BOP).

Deliverables

This report provides screening level capital cost, performance, operations and maintenance

(O&M) costs, availability factors, and emission rates for the two IGCC alternatives defined above. As a part of creating this information Burns & McDonnell also generated process flow diagrams, layout drawings, water mass balances, and electrical one-line diagrams.

Another objective of this study was to compare IGCC technology to supercritical pulverized coal

(SCPC) technology using steam conditions of 3500 psig/1050°F/1050°F. Therefore capital cost, performance, O&M costs, availability factors, and emission rates were also developed for a

SCPC Unit firing 100% PRB coal with a net output of 550 MW. This information was used to create a 20-year levelized busbar cost to determine the overall cost of generation for the three alternatives.

The addition of CO

capture equipment was also evaluated as a retrofit for the 100% PRB IGCC and SCPC facilities. UOP’s SELEXOL system was used as the basis for the IGCC CO

capture technology and Fluor’s Econamine FG Plus

system was used for SCPC CO

capture technology. Capital cost, performance, O&M, and emission rates were developed and used to calculate a 20-year levelized busbar cost for both technologies.

Results

A summary table is provided in Table 1-1 and Table 1-2.

1-2

Executive Summary

Table 1-1

Executive Summary Table (Table 1 of 2)

Case

Fuel

PRB (% wt.)

Petcoke (% wt.)

PRB (% heat input)

Petcoke (% heat input)

HHV (Btu/lb)

Capital Cost (2006 USD)

EPC Capital Cost

Owner's Costs

Total Project Cost

EPC Capital Cost, $/kW (73°F Ambient)

Total Project Cost, $/kW (73°F Ambient)

Performance

43°F Dry Bulb, 40°F Wet Bulb

Gross Plant Output, MW

Auxiliary Load, MW

Net Plant Output, MW

Net Plant Heat Rate, Btu/kWh (HHV)

73°F Dry Bulb, 69°F Wet Bulb

Gross Plant Output, MW

Auxiliary Load, MW

Net Plant Output, MW

Net Plant Heat Rate, Btu/kWh (HHV)

93°F Dry Bulb, 77°F Wet Bulb

Gross Plant Output, MW

Auxiliary Load, MW

Net Plant Output, MW

Net Plant Heat Rate, Btu/kWh (HHV)

O&M Cost (2006 USD)

Fixed O&M, $/kW-yr

Variable O&M, $/MWh

Total O&M Cost, $/Year (85% CF)

Availability Factor

100% PRB

100%

8,156

$1,318,980,000

$155,240,000

$1,474,220,000

$2,390

$2,670

736.6

137.4

599.2

9,090

709.9

156.8

553.0

9,220

681.5

153.2

528.4

9,350

$25.19

$5.95

$38,426,700

85%

Base Cases

IGCC

50% PRB / 50% Petcoke

50%

36%

64%

11,194

$1,287,540,000

$139,500,000

$1,427,040,000

$2,330

$2,580

734.2

137.2

597.0

8,950

711.1

158.0

553.0

9,070

682.6

154.5

528.2

9,210

$25.19

$5.66

$37,245,400

85%

SCPC

100% PRB

100%

8,156

$1,072,580,000

$129,760,000

$1,202,340,000

$1,950

$2,190

623.3

65.4

557.8

9,030

614.5

64.5

550.0

9,150

613.2

64.4

548.8

9,170

$20.68

$4.60

$30,209,800

90%

Capture Cases

IGCC

100% PRB IGCC

SCPC

100% PRB

100%

8,156

100%

8,156

$179,220,000 (Note 1)

$17,960,000 (Note 1)

$197,180,000 (Note 1)

$3,630 (Note 1)

$4,040 (Note 1)

Not Evaluated

630.1

216.8

413.3

12,800

Not Evaluated

$34.74

$8.55

$40,661,400

Not Evaluated

$269,430,000 (Note 1)

$26,570,000 (Note 1)

$296,000,000 (Note 1)

$3,440 (Note 1)

$3,840 (Note 1)

Not Evaluated

521.4

131.6

389.8

12,910

Not Evaluated

$31.19

$6.97

$32,563,000

Not Evaluated

Economic Analysis

Capacity Factor

20-year levelized busbar cost, $/MWh (2006 Real $)

Avoided CO

Cost, $/Mt CO

avoided

85%

$45.03

N/A

85%

$40.89

N/A

85%

$39.28

N/A

$65.41

$26.28

N/A

$62.00

$29.64

Notes:

1) CO

Capture capital costs are based on retrofit of the existing IGCC or PC facilities as provided in the base case alternatives. $/kW values reflect total installed cost to date (including original costs provided in the base case) divided by net plant output with CO2 capture.

1-3

Executive Summary

Table 1-2

Executive Summary Table (Table 2 of 2)

Case

NO x

Emissions lb/MMBtu (HHV) ppmvd @ 15% O

2 lb/MWh (net)

Emissions lb/MMBtu (HHV) lb/MWh (net)

Emissions (front half) lb/MMBtu (HHV) lb/MWh (net)

CO lb/MMBtu (HHV) ppmvd lb/MWh (net)

2 lb/MMBtu (HHV) lb/MWh (net)

% Removal lb/TBtu (HHV) lb/MWh (net)

100% PRB

0.063

0.581

0.019

0.173

0.007

0.065

0.037

0.337

215

1,985

90%

0.778

7.17E-06

IGCC

Base Cases

50% PRB / 50% Petcoke

0.062

0.562

0.023

0.210

0.007

0.065

0.036

0.337

213

1,934

90%

0.496

4.50E-06

SCPC

100% PRB

0.050

N/A

0.458

0.060

0.549

0.015

0.137

0.150

N/A

1.373

215

1,967

70%

2.315

2.12E-05

IGCC

Capture Cases

100% PRB IGCC

0.061

0.781

0.004

0.051

0.007

0.090

0.035 (Note 1)

25 (Note 1)

0.448 (Note 1)

276

90%

0.778

9.96E-06

SCPC

100% PRB

0.045

N/A

0.581

0.0003

0.003

0.015

0.194

0.150

N/A

1.937

278

70%

2.315

2.99E-05

Plant Cooling Requirements, MMBtu/hr (@ 73°F)

Steam Cycle Cooling Requirement, MMBtu/hr

BOP Auxiliary Cooling Requirement, MMBtu/hr

Total Plant Makeup Water Requirement

GPM (@ 73°F)

Acre-ft/year (@ 85% CF)

2,141

1,480

661

4,980

6,830

2,179

1,480

699

5,231

7,170

2,490

2,300

190

5,800

7,950

2,101

1,120

981

6,147

8,430

3,330

1,354

1,976

7,757

10,640

Notes:

1) GE is currently in the process of developing tools to accurately predict CO emissions for high hydrogen fuels. It is estimated that CO emissions will be less than shown for IGCC CO

capture technology, however to what extent is unknown at this time.

1-4

Executive Summary

The capital costs are based on mid-2006 overnight EPC costs. Escalation through a commercial operation date (COD) is not included. Additionally, sales tax, interest during construction, financing fees, and transmission lines or upgrades are not included in the capital cost estimates.

As can be seen SCPC technology provides the lowest capital cost, best efficiency, and lowest

O&M when comparing the two 100% PRB options. Additionally, the 100% PRB SCPC unit has the lowest busbar cost of all alternatives.

The heat rate for the fuel blended IGCC case is slightly better than 100% PRB SCPC technology

(with the exception of the 93°F case); however firing petcoke in a PC unit is also possible, although not specifically evaluated for this report. Petcoke firing in a conventional PC boiler is typically limited to approximately 20% (by heat input) due to the low volatiles present in the fuel which can create flame stability issues. Firing 20% petcoke in the PC boiler will result in approximately 1% improvement in heat rate over that shown for the PC unit, thus closing the gap, if not eliminating any performance benefit of the IGCC.

IGCC has an advantage in terms of SO

, PM

, and mercury emissions, however using the emissions allowance costs provided in Chapter 8, these lower emissions are not enough to overcome the capital cost and performance differences between the technologies.

The IGCC evaluated has higher NO x

emission rates than for the SCPC unit. This is because an

SCR was not included for the IGCC unit due to concerns that ammonium bisulfate (ABS) deposits could plug and corrode the heat transfer surfaces of the HRSG downstream of the SCR.

Additionally, if an SCR were used, a larger AGR and SRU would be required to lower the sulfur content of the syngas (to reduce particulate formation from the excess ammonia with SO

/SO

in the flue gas) resulting in increased capital cost. For these reasons, an SCR was not included; however subsequent evaluations should be performed to evaluate the cost/benefit/technological risk tradeoff. If an SCR were used, NO x

emissions could be reduced to levels below that provided for the SCPC unit.

IGCC technology consumes less water than SCPC technology. This is primarily due to the steam turbine output of the IGCC being less than half that of the SCPC unit. Although the steam condenser duty is less for the IGCC, the auxiliary cooling requirements of the IGCC are higher than the SCPC unit (primarily due to the ASU cooling requirement), resulting in about a 15% overall lower cooling tower duty and water consumption.

The installation of CO

capture equipment as a retrofit for both of these technologies results in a very significant decrease in plant output. The IGCC net plant output decreases by approximately

All of these factors result in an increase of the 20-year levelized busbar cost by approximately

45% for the IGCC and 58% for the SCPC post CO

capture. SCPC technology still provides the lowest busbar cost after CO

capture retrofit, although by less of a gap than pre-CO

capture.

The avoided cost of CO

capture is less for an IGCC implying that IGCC technology is the more economical choice for retrofit of CO

capture technology (if you owned both an existing IGCC

1-5

Executive Summary

plant and SCPC plant and were going to retrofit only one, you would choose the IGCC), however the lower initial capital cost (pre-capture) of SCPC technology still results in an overall lower busbar cost for SCPC technology.

This is the first EPRI study performed that evaluates CO

capture as a retrofit to existing IGCC and SCPC units. Other EPRI studies have evaluated CO

capture on new units specifically designed for and incorporating CO

capture from the start vs. new units that are not designed with CO

capture in mind. This study attempts to answer the question of what are the impacts from adding CO

capture to an existing SCPC or IGCC plant at a later date.

The Shell gasification process chosen for this application utilizes a dry-feed system, which has advantages over slurry-feed gasification processes for low rank coal (for the non-CO

capture case). The Shell gasifiers produce syngas with higher concentrations of CO and less H

than would be produced by a slurry-feed gasifier. When adding CO

capture equipment to the Shell gasification process, more steam is required to convert the CO to CO

and H

2 than would be required for a slurry-feed gasifier. This results in less steam available to the steam turbine, which equates to less plant output for the CO

capture case than may be seen if using a slurryfeed gasifier. If the objective of the Owner is to capture CO

, then a slurry-feed gasifier may be a better choice than a dry-feed gasifier.

Additionally, this is the first detailed study performed by EPRI that evaluates IGCC and PC technology with CO

capture when using a lower rank, higher moisture PRB coal. Other detailed studies performed by EPRI focused primarily on higher rank bituminous coals (using slurry-feed gasifiers), where IGCC has been shown to provide a more distinct advantage.

The performance information provided by UOP and Fluor for the CO

capture equipment is different from data obtained for other recently published studies. A resolution of the differences is outside the scope of this project, however it is anticipated that the differences are related to the

purity that was specified for this project. It should be noted that none of the technologies

(IGCC, SCPC, or CO

capture) evaluated in this study were optimized to provide the best costto-benefit ratio (i.e. lowest busbar cost). The designs used as the basis for this evaluation are just one of many possible configurations that should be further optimized in the future.

Changes in market conditions, improvements in IGCC technology, different fuel specifications, or CO

purity specifications could be enough to swing the economics in favor of IGCC.

Therefore, it is recommended that utilities consider IGCC technology for future generation needs. However, based on the results and design basis used in this study, SCPC provides the lowest busbar cost of the three alternatives at this time.

Current Market Conditions

In recent years, several factors have caused the cost of power projects to increase at a higher rate than in years past. Specifically in the Gulf Coast area, the destruction of Hurricane Katrina has resulted in a large labor demand for reconstruction efforts. In order to meet labor requirements, much of the construction labor force has been pulled from out of state, resulting in a construction labor shortage across the country (in an industry that was already in high demand). The high demand for qualified labor has resulted in “job-hopping” for many workers. The result is that

1-6

Executive Summary

labor productivity has been very poor compared to that of just a few years ago, yet the cost of construction labor is increasing at a rapid rate.

In addition to Hurricane Katrina rebuilding projects, engineering firms and construction contractors are very busy with new power generation projects and air pollution control projects designed to clean up SO

and NO x

emissions from older coal-fired units. This increased demand results in increased contingency, overhead, and profit levels for contractors. Some clients have even had challenges finding qualified contractors that are willing to bid on their projects.

Beyond labor issues, the world demand for many commodities has also increased sharply, due in large part to China’s economic growth. This high demand has resulted in a 100-300% cost increase for some commodities including steel (in particular stainless or high alloy steel), concrete, copper, oil, and nickel resulting in increased equipment costs and vendor markups.

The compounding effect of labor productivity, high labor rate escalation, commodity cost escalation, risk mitigation, and contractor markups results in much higher project costs than may have been anticipated one or two years ago.

Limitations and Qualifications

The estimates and projections prepared by Burns & McDonnell relating to construction costs, performance, and O&M are based on our experience, qualifications, and judgment as a professional consultant. Since Burns & McDonnell has no control over weather, cost, and availability of labor, materials, and equipment, labor productivity, unavoidable delays, economic conditions, government regulations and laws (including interpretation thereof), competitive bidding and market conditions or other factors affecting such estimates or projections, Burns &

McDonnell does not guarantee that actual rates, costs, performance, etc., will not vary from the estimates and projections prepared herein.

1-7

INTRODUCTION

Background

CPS Energy, located in San Antonio, Texas, is the nation’s largest municipally owned energy company providing both electricity and natural gas to its customers. In December of 2005, CPS

Energy agreed to fund an IGCC study, as part of a settlement during the air permitting process for a new pulverized coal plant. Under the terms of the agreement, the IGCC study scope compares SCPC and IGCC technologies at a generic site in Texas. CPS Energy also agreed to make the report available to the public. This study provides typical decision support input for a power plant investment decision for a generic municipally-owned utility. The study includes generic investment decision information such as, cost of capital, forecasted fuel costs, etc. The study does not include competitive, sensitive CPS Energy power plant investment decision information.

CPS Energy contacted Burns & McDonnell to perform a technical and economic feasibility study for a nominal 550 MW 2x1 IGCC unit.

Objectives

The primary objectives of this study were to provide screening-level information for use in evaluating a 2x1 IGCC facility to be located at a generic Texas Gulf Coast site. This information consists primarily of capital cost, performance, and O&M cost estimates.

To achieve these objectives, Burns & McDonnell provided a conceptual design for the facility, consisting of preliminary process design, overall plant heat balances, preliminary process flow diagrams, preliminary electrical one-line diagrams, and preliminary site layout drawings. This information was then used to establish the plant preliminary capital cost estimate.

Once the conceptual design information was produced, IGCC technology was compared to conventional coal fired SCPC technology in a pro forma economic analysis to determine which technology resulted in the lowest busbar cost of the facility.

Additionally, the impacts of adding CO

capture as a retrofit to the IGCC and SCPC technologies were evaluated. The impacts for performance, capital cost, O&M, emissions, and levelized busbar cost were determined.

If any of the technologies presented in this report are of interest to the Owner, it is recommended this feasibility study be followed up with more detailed studies to further define the project and

2-1

Introduction

to tailor the information for a specific site. These follow-on studies should include gasifier and gas turbine manufacturer involvement.

Status of the Technology

Conventional combined cycle technology is a proven technology that has been used for many years in the power industry. Similarly, gasification technology is a proven technology that has been used extensively in the chemical industry to produce products such as ammonia and hydrogen. IGCC technology combines these two proven technologies by producing a medium-

Btu value syngas from coal or other solid fuel (petcoke) and firing it in a modified conventional gas turbine as part of a combined cycle application.

When combining these two technologies, high levels of integration between the two processes are often required to increase plant efficiency and to make IGCC competitive with other coalfired electric power generation technologies. This integration is created by using heat exchangers to capture heat produced in the gasification process and utilizing it to increase the output and efficiency of the steam cycle, yet at the same time increasing the complexity of the plant.

IGCC projects generally utilize conventional equipment (gas turbines, heat exchangers, compressors), that when combined with the complexity of integration into an IGCC facility, has led to less than desirable availability factors and forced outage rates in the past. It has generally been the failure of this “conventional” equipment that has lead to the poor reliability and availability of the existing IGCC facilities. It is anticipated that advancements in IGCC design and increased IGCC operational experience are expected to improve availability and lower the forced outage rates for IGCC technology.

Development of the IGCC technology truly commenced in the 1970’s during the energy crisis.

Research and development during this timeframe led to the construction of the Texaco Cool

Water facility in California, and the LGTI facility in Louisiana. Both of these facilities have been decommissioned. Experiences and lessons learned from these facilities were brought forward during the 1990’s with the development of the Polk and the Wabash IGCC facilities.

Ongoing operation of these two facilities in the United States and the Buggenum and Puertollano facilities in Europe continue to help improve the future generation of IGCC facilities.

Selection of Gasification Technology

Burns & McDonnell was requested to perform a cursory evaluation of the gasification technologies available, and select a technology to be used as a basis for this study. Focus was given only to the major technologies that currently have commercial IGCC offerings in the

United States. This consists of GE, ConocoPhillips, and Shell gasification technologies.

GE and ConocoPhillips use slurry-feed gasifiers, whereas Shell uses a dry-feed gasifier. Slurryfeed gasifiers typically work well on high rank bituminous coals. When utilizing PRB as a feedstock, however, the slurry has a lower concentration due to the high inherent moisture content of the PRB coal. As a result of feeding less dense slurry to the gasifier, the cold gas

2-2

Introduction

efficiency decreases and oxygen consumption increases, typically resulting in decreased performance.

GE has several gasifiers operating in the United States and worldwide. The GE gasification technology is an oxygen-blown slurry-feed entrained flow gasifier. Most of the operating GE gasifiers are the quench design. Their IGCC offering is the radiant design intended to maximize the steam production for power generation. The GE gasification process works well on bituminous coal and/or petcoke, and they are currently working on a design for PRB, with the intention of having a commercial offering toward the end of 2006. GE was approached about participating in this study, and due to their current workload, declined to participate.

ConocoPhillips has an operating, full commercial scale gasifier at the Wabash IGCC facility.

Their process is a 2-stage oxygen-blown slurry-feed entrained flow gasifier. At the LGTI IGCC facility, which was decommissioned in 1995, ConocoPhillips gasified over 3.7 million tons of

PRB. ConocoPhillips was also approached about participating in this study, and due to their current workload, declined to participate.

Shell currently has three coal gasifiers operating worldwide. Two started up this year in China and the Shell gasifier is used at the NUON IGCC facility in the Netherlands. Eleven other Shell coal gasifiers are currently under construction in China. The Shell coal gasification process is an oxygen-blown dry-feed entrained flow gasifier that is suitable for PRB gasification. The dryfeed system of the Shell gasifier also likely provides some performance benefits over slurry-feed gasifiers when designing for low-rank coals such as PRB. Shell was approached about participating in the study and also declined to participate directly, but agreed to allow EPRI to perform modeling of their gasification system and supply the results to Burns & McDonnell.

Based on the likely performance benefits associated with the Shell process for PRB coal, it was agreed that the Shell gasification process would be used as the basis for this evaluation.

It should be noted that all of the gasification technologies described above perform differently and have different O&M requirements. The GE and ConocoPhillips gasifiers are refractory lined, whereas the Shell gasifier has a steam tube membrane wall. The refractory lined gasifiers require a periodic replacement of the refractory due to wear in the high slag flow areas, whereas the membrane wall tubes require little maintenance. Also, the Shell process is a dry-feed, versus slurry-feed for the GE and ConocoPhillips processes. Due to the higher concentrations of water, the syngas from the GE and ConocoPhillips gasifiers has higher concentrations of CO

and H

2 and the syngas from the Shell process has a higher concentration of CO.

Project Experience

Table 2-1 shows the current and previous IGCC facilities that were developed in the United

States and in Europe. All of the United States facilities were developed with funding assistance from the Department of Energy.

2-3

Introduction

Table 2-1

IGCC Facilities – Past and Current

Facility

Puertollano

Polk

County

Wabash

River

Buggenum

Pinon Pine

LGTI

Cool Water

Owner

Capacity

(MW)

Commercial

Operation

Date

Gasifier

Manufacturer

Status

Elcogas 321 1998 Prenflo Operating

Tampa

Electric

252 1996 GE Operating

PSI Energy 262 1995 Conoco Phillips Operating

NUON 254 1994 Shell Operating

Sierra

Pacific

Dow

Chemical

Texaco 125 1984 GE Decommissioned

Fuel experience

Within the United States, relatively little IGCC experience exists with PRB as the feedstock. As noted previously, between 1987 and 1995, the LGTI facility gasified over 3.7 million tons of

PRB. This represents the majority of the United States operating experience with PRB gasification.

There has been significant operating experience with petcoke. Petcoke lends itself well to gasification due to the higher heating content, low moisture, and low ash. However, petcoke does have significantly higher sulfur content. Due to the trace metals in the petcoke, either a fluxant or coal needs to be blended with the petcoke to enable the ash to flow out of the slagging gasifiers. Currently, the fuel for the Polk IGCC facility is a blend of coal and petcoke, and petcoke is being utilized at the Wabash IGCC facility.

Shell has processed both PRB coal and petcoke during the early 1990s at a 250 tpd demonstration plant at Shell’s Deer Park, TX refinery. Shell has reported a cold gas efficiency of 78.0% with 99.7% carbon conversion and 99.9% sulfur capture during 297 hours of tests on

PRB and 78.9% cold gas efficiency with 99.5% carbon conversion and 99.8% sulfur capture during 169 hours of operations on petcoke.

Technical Approach and Data Sources

As noted above, the Shell coal gasification process was selected for this study. EPRI provided the gasifier yield and thermal performance for the gasification plant (up to the wash column inlet). Burns & McDonnell performed the preliminary design of the low temperature gas cooling and scrubbing section, COS/HCN catalyst section, AGR, SRUs, TGTU, power block, and balance of plant. The following vendors were used to provide additional information:

• UOP provided an equipment list and performance information for the SELEXOL unit.

2-4

Introduction

• Air Liquide Process and Construction (ALPC) provided cost and performance information for the ASU.

• Sud-Chemie provided cost and performance information for the COS/HCN catalyst.

• NUCON provided cost and performance information for the mercury removal bed.

• Fluor provided cost, performance, and emissions information for the Econamine FG Plus

Plant (EFG+) for SCPC CO

capture.

The information provided herein does not represent a thorough performance or cost optimization.

Further optimizations (capital cost investment vs. performance, emissions, or O&M benefits) can be performed that would likely improve the busbar cost of all technologies (SCPC, IGCC, and

capture).

2-5

STUDY CRITERIA

Site Selection

The site for this project is based on a generic greenfield site located in the Texas Gulf Coast.

The ambient conditions used as the design basis of this study are the 2% dry bulb (dry bulb temperature is exceeded 2% of the year), average dry bulb, and 95% dry bulb (dry bulb temperature is exceeded 95% of the year)

The ambient conditions are as follows:

• 2% Dry Bulb: 93°F with coincident wet bulb temperature of 77°F.

• Average Dry Bulb: 73°F with coincident wet bulb temperature of 69°F.

• 95% Dry Bulb: 43°F with coincident wet bulb temperature of 40°F.

The finished grade of the site is assumed to be 100 ft. Additional assumptions about the site can be found in Chapter 7.0

Gas Turbine Selection

The gas turbines selected as the basis for this project are GE 7FB gas turbines. EPRI and Burns

& McDonnell have access to more readily available information for GE’s 7FB gas turbines than from other manufacturers. Also, GE has much experience with syngas operation, having accumulated over 300,000 hours of operation on syngas; however GE has no operating experience with firing syngas in the 7FB. Although GE has this significant syngas operating experience, other gas turbine manufacturers are able to offer similar gas turbines that should result in a comparable result.

Fuel Selection

PRB fuel is currently utilized by several utilities in Texas. This low-sulfur coal has proven to be an economical choice for generation in Texas.

Additionally, petcoke, a byproduct of the refining process, has proven to be an economical fuel alternative for other generating facilities across the nation. Refineries are typically eager to

3-1

Study Criteria

remove this byproduct from their site; therefore petcoke is relatively inexpensive from the refinery. The expense of petcoke is dictated by transportation costs from the refinery to the power plant. The prospect of petcoke firing is typically limited by the following factors:

1) Projects planning to fire petcoke are typically located near refineries that produce coke as a byproduct.

2) The quantity of petcoke is typically only available in sufficient quantities to supply a part of the overall heat input to a large power facility.

3) Firing 100% petcoke in a PC unit is only achievable using a special down-fired boiler.

Conventional designed PC units are limited to approximately 20% petcoke firing due to the low volatiles in the coal.

Therefore, petcoke is typically blended with other fuels when used in large scale power generation.

Because this project is located in the Texas Gulf Coast, petcoke should be available as an alternate fuel source from nearby refineries. Therefore, two independent IGCC options were evaluated for this project:

• Option 1 – 100% PRB Coal

• Option 2 – 50% PRB Coal / 50% Petcoke (% by weight)

Fuel analyses are provided in Table 3-1.

3-2

Study Criteria

Table 3-1

Fuel Analyses

PRB (% wt.)

Petcoke (% wt.)

PRB (% heat input)

Petcoke (% heat input)

HHV (Btu/lb)

Proximate Analysis (% wt.)

Moisture

Volatile Matter

Fixed Carbon

Ash

Ultimate Analysis (% wt.)

Carbon

Hydrogen

Nitrogen

Chlorine

Sulfur

Oxygen

Ash

Moisture

Total

Mercury (ppm)

Ash Fusion Temperatures

Reducing Atmosphere

Initial Deformation

Softening

Hemispherical

Fluid

Oxidizing Atmosphere

Initial Deformation

Softening

Hemispherical

Fluid

100% PRB

100%

8,156

30.24

31.39

33.05

5.32

48.18

3.31

0.70

0.01

0.37

11.87

5.32

30.24

100.00

0.091

2150°F

2170°F

2190°F

2210°F

2220°F

2240°F

2260°F

2280°F

100% Petcoke

100%

14,231

4.83

10.60

84.44

0.13

83.62

3.02

0.85

0.01

6.60

0.94

0.13

4.83

100.00

0.05

2800+°F

2,505°F

2,597°F

2,610°F

2,611°F

50% PRB / 50% Petcoke

50%

36.40%

63.60%

11,194

17.53

21.00

58.74

2.73

65.88

3.17

0.78

0.01

3.49

6.41

2.73

17.53

100.00

0.07

N/A

Plant Capacity Selection

The largest IGCC facility that has been constructed in the United States is a 1x1 (one gasification/gas turbine/HRSG train and one steam turbine). Currently, 2x1 IGCC technology is the primary focus of IGCC development by both manufacturers and developers due to improved economies of scale. It is possible to improve the economies of scale of an IGCC facility further by adding an additional gasification/gas turbine/HRSG train (3x1 facility). However due to a general aversion to risk in the industry, it is unlikely that a 3x1 IGCC facility will be developed until 2x1 IGCC technology has been proven successfully in the United States. Therefore, a 2x1

IGCC facility is the basis of this study.

3-3

Study Criteria

The plant capacity for this project is dictated by the capacity of the gas turbines coupled with the available energy that can be recovered from the gas turbine and gasification process. For this project, the 2x1 IGCC facility has a nominal net plant output of 550 MW.

Capacity Factor and Availability Factor Targets

Capacity Factor (CF) is defined as the actual MWh produced in a year divided by the maximum possible MWh produced in a year. Generally, capacity factors for units are dictated by economic issues. Lower production cost technologies operate at base load (capacity factors above 70%), whereas higher production cost technologies tend to operate as “peaker” plants or for serving an intermediate load (operating throughout the day and ramping down at night).

The large capital and operating expenditure (yet lower fuel cost) of a coal plant are typically only justified by operating the unit at base load. Due to the increase of natural gas prices and limited base load resources, capacity factors of conventional PC plants are typically at 85% or higher.

The O&M estimates and economic evaluation provided in this study assume a capacity factor of

85%, with a 100% load factor (operating 85% of the time at full load and off-line the other 15% of the time).

The Availability Factor (AF) is defined as the sum of service hours and reserved shut down hours divided by the total hours per year. Essentially, it is the percentage of hours in a year that the plant is available to operate.

Some IGCC facilities have been evaluated with a spare gasifier to increase availability factors and allow increased operational flexibility. It was decided that the increased operating and capital expenses of the spare gasifier are not justified for this project at this time. The resulting availability factor is approximately 85% for the IGCC technologies evaluated.

Additional information on plant availability factors can be found in Chapter 9.0.

3-4

PROCESS DESCRIPTION

Gasification System Description

For this report, the Gasification System refers to all of the equipment required to make syngas.

This includes the ASU, gasifiers, slag handling, candle filters, wash towers, COS/HCN hydrolysis, mercury removal, syngas cooling and condensation, AGR, SRUs, tail gas treatment, sour water stripping, and syngas saturation. Process flow diagrams are included in Appendix A for reference. A block flow diagram is provided in Figure 4-1.

Figure 4-1

Gasification Block Flow Diagram

Air Separation Unit (ASU)

Atmospheric air is dried and then cryogenically distilled in the ASU to produce 95% oxygen and several nitrogen steams. The air separation unit selected for this study is a high-pressure ASU, meaning that the columns all operate at a higher pressure than a conventional low-pressure ASU.

The selection of an HP or LP ASU depends primarily on the amount of nitrogen required under

4-1

Process Description

pressure vs. the oxygen requirement. Because of the large nitrogen requirement, the primary benefit of the HP ASU is the reduced power requirement for N

compression.

The majority of the oxygen produced in the ASU is supplied at high pressure (780 psia) for use in the gasifiers. A small amount of low pressure oxygen is used as the oxidant in the SRU.

Uses for the nitrogen streams are as follows:

• High pressure (1089 psia) N

with 0.1% O

is used for conveying the fuel into the gasifier and other purposes in the gasification block.

• Medium pressure (480 psia) N

with 2% O

is used as diluent in the gas turbines for NO x control.

• Low pressure (140 psia) N

with 2% O

is used for regeneration of the molecular sieve driers and miscellaneous purges.

Cryogenic pumps are used to supply the high pressure nitrogen and oxygen streams to the gasifier. The cryogenic pumps were chosen because of their lower auxiliary power consumption and lower cost than gas compression. Additionally, pumping liquid O

is generally viewed to be safer than compression of gaseous O

. The high-pressure liquid oxygen and nitrogen are then vaporized prior to the gasifier. The medium pressure and low pressure nitrogen streams are pressurized by nitrogen compressors.

The ASU scope includes storage of high-pressure, high-purity nitrogen equivalent to 12 hours of production in liquid form. Additionally, 20 minutes of production as gas is available at pressure to provide nitrogen during the period of time that back-up liquid vaporization comes on line.

The back-up system is to be designed to deliver high pressure nitrogen within 10 minutes after being activated.

The material balances around the ASU for the 100% PRB cases (43°F and 93°F) are provided in

Table 4-1, which are used to set the design requirements of the ASU. Since very little difference exists between the ASU for the 100% PRB case and the 50% PRB / 50% petcoke case, the same

ASU design was used for both options. Additionally, Figure 4-2 provides a block flow diagram for a generic ASU.

4-2

Process Description

Table 4-1

ASU Material Balances

Stream

H2O

Total

% O2

Temp, F

Pres. psia

Total lb/hr

Case 93F PRB Coal

<------------------------------------Nitrogen Product Streams----------------------------->

Total Air In Total Dry Air O2 Product Conveying HP To Process LP Misc Sieve Regen. Remaining N2 to GT Ambient Air GT Air lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr

1,390 1 1,392

11,057 11 11,068 11,068 10,383 2 lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr

1,392

2 187 490 677

41,211

492

54,150

20.4%

41,252

492

54,204

20.4%

41,252

492

52,812

21.0%

164

383

10,930

95.0%

1,930

1.9

1,934

0.1%

4,000

4.1

4,008

0.1%

1,555

1.6

1,559

0.1%

9,164

9,360

2.0%

24,439

25,021

2.0%

33,603

102

35,773

1.9%

1,552,965

810

218

1,547 1,554,511 1,529,437

382

760

352,142

280

1068

54,206

280

1068

112,353

140

43,692

140

263,066

140

703,991

453

290

992,132

Stream

H2O

Total

% O2

Temp, F

Pres. psia

Total lb/hr

Ambient Air GT Air Total Air In Total Dry Air O2 Product Conveying HP To Process LP Misc Sieve Regen. Remaining N2 to GT lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr lb-moles/hr

253 168 422 422

7,281

27,138

323

34,996

20.8%

4,854

18,092

216

23,330

20.8%

12,135

45,230

539

58,326

20.8%

12,135

45,230

539

57,904

21.0%

11,360

179

419

11,958

95.0%

1,930

1.9

1,934

0.1%

4,000

4.1

4,008

0.1%

1,555

1.6

1,559

0.1%

187

9,164

9,360

2.0%

580

28,402

103

29,085

2.0%

767

37,566

113

38,867

2.0%

1,010,697

810

218

673,785 1,684,482 1,676,887

Case 43F PRB Coal

<------------------------------------Nitrogen Product Streams----------------------------->

382

760

385,263

280

1068

54,206

280

1068

112,353

140

43,692

140

263,066

140

453

290

818,321 1,088,982

Note: The air provided by the GTG (stream 2) is cooled to ambient temperature by heat exchange with steam cycle condensate and auxiliary cooling water prior to being sent to the ASU. The N

to the gas turbine (stream 11) is heated from ~350°F at the discharge of the final stage of compression to 453°F using IP boiler feedwater as the heat source prior to the gas turbine.

The following major equipment items are included:

• Main air compressor and booster air compressor (2 trains x 50%).

• Nitrogen compressor (2 x 50%).

• Cryogenic oxygen pumps (2 x 100%).

• Cryogenic nitrogen pumps (2 x 100%) for high pressure N

• Cold box.

• Switching valves, driers and regeneration heater.

• MV and LV Switchgear and MCC.

• Transformers from 13.8 KV.

• Liquid N

storage and associated backup vaporizer.

• Electrical / control room.

• Commissioning spares.

4-3

Process Description

Figure 4-2

Generic ASU Process Flow Diagram

Additionally, heat exchangers are provided to cool the extracted air from the gas turbine to ambient temperature prior to the ASU and to heat the nitrogen from the ASU to the gas turbine.

These costs are not included in the ASU cost provided by ALPC, however they are included in the BOP costs.

Gasifiers

The gasification plant for this project is comprised of two Shell oxygen-blown entrained-flow gasifiers, each capable of supplying enough syngas for operation of one gas turbine at full load.

Each gasification train is comprised of coal milling and drying equipment, coal pressurization lockhopper, high pressure oxygen and coal feed systems, gasifier vessel, slag removal system, syngas cooling, syngas recycle compressor, and particulate removal systems.

The Shell gasifier uses a dry-coal feed system. This system requires the feedstock moisture content to be reduced to approximately 5% prior to injection to the gasifier. Therefore, coal drying equipment is required which utilizes syngas (or natural gas during startup) to drive off the excess moisture in the fuel. The coal dryer is combined with the coal milling equipment in a vertical roller mill which pulverizes the coal to the required consistency. The dried and pulverized coal is raised above the gasifier operating pressure in a set of lockhoppers and conveyed to the gasifier using high pressure nitrogen. PRB fuel is highly reactive and has a high potential for spontaneous combustion; consequently the oxygen concentration in the milling/drying and coal feeding systems is minimized via the injection of nitrogen at various locations. A detailed evaluation of the operation of the coal dryer relative the PRB fuel was not performed.

4-4

Process Description

The fuel and high pressure oxygen react in the gasifier at high temperatures (2,700 ºF) and approximately 560 psia to produce syngas. The gasifier, operating in an oxygen deficient

(reducing) atmosphere, is designed to operate at conditions suitable to promote reactions which produce a synthesis gas (syngas) and slag. The syngas produced in the gasifiers is rich in hydrogen, carbon monoxide, and water. There are also lesser amounts of several components including carbon dioxide, hydrogen sulfide, carbonyl sulfide, methane, argon, and nitrogen.

The gasifier vessel walls are cooled using water-wall membranes that produce medium-pressure

(MP) steam at approximately 650 psia. The syngas is quenched by recycle of cooled, particulate-free syngas to ~1,700°F. The syngas then passes to the syngas cooler which also uses medium pressure feedwater as a cooling medium. Heat from the syngas is transferred to the feedwater resulting in the generation of medium pressure saturated steam that is transferred to the HRSG in the power block for superheating and re-introduced to the steam turbine as “hot reheat” steam. After being partially cooled in the syngas cooler, the syngas passes through a candle filter to remove entrained solids from the syngas. Additionally the syngas is passed through a water wash scrubber which is primarily used to remove fine particulate, chlorides, and any other water-soluble compounds (see Syngas Wash Towers section below).

Alternatively, HP steam can be generated in the syngas cooler, however this greatly increases the cost of the syngas cooler and associated piping (alloy materials vs. carbon steel), resulting in

~$60-$70 million increase in total project cost. Shell claims that the use of HP steam generation in the syngas cooler can result in a 1.5% improvement in IGCC efficiency; however this option was viewed as cost prohibitive at this stage of the project. It is recommended that this option be evaluated in more detail at a later developmental stage of the project.

Gasifier Performance Estimate by EPRI

EPRI used its internal IGCC modeling tool, which uses a Gibbs Free Energy Minimization approach to estimating gasifier product composition and temperature. EPRI relied heavily on the performance data Shell published in a 2004 Gasification Technologies Conference paper to set the inputs for the gasifier model. That paper presented performance estimates for the Shell coal gasification process on a generic Powder River Basin coal and on a 50/50 mixture of PRB and petcoke. One difference between the Shell design premises and those used by EPRI was the purity of the oxygen feed stream. Shell assumed it was 99 v% O

, while EPRI chose 95 v% as several engineering studies have shown that to be the optimal value for IGCCs producing power only.

A summary of the main inputs and outputs from the gasifier performance model at the 43°F ambient condition is provided in Table 4-2.

4-5

Process Description

Table 4-2

Summary of Gasifier Modeling Results

100% PRB

Model Inputs

/coal feed ratio (95v% O

) lb/lb-coal

0.771

Steam/coal lb/lb-coal

0.034

/coal lb/lb-coal

0.110

Syngas Exit Pressure psia 574

Heat Flux to Gasifier Wall

Carbon Conversion

Model Results

%coal HHV

0.6

99.5

Syngas Exit Temperature ºF

Gasifier Wall Steam Production MMBtu/hr

Syngas Exit Composition

COS

HCN

%vol

Feed Rate

Steam Feed Rate lb/hr lb/hr

2732

32.7

59.91

0.013

0.005

0.97

377,816

16,688

50% PRB / 50%

Petcoke

0.881

0.104

0.107

574

1.4

99.0

2913

74.8

64.85

0.110

0.011

1.02

364,983

42,939

for Coal Conveying

Coal Feed Rate

2 lb/hr lb/hr

MMBtu/hr

Unquenched Syngas Flow Rate lb/hr

54,069

490,171

5,444.3

901,760

Syngas Production Rate

MMBtu/hr 4,561.7

Flyslag (overhead) Production lb/hr 10,084

44,371

414,125

5,340.7

850,367

4,453.4

6,185

Slag (bottom) Production

Cold Gas Efficiency lb/hr

26,900

83.8

9,866

83.4

As fed coal basis (dried to 5 wt% H

HHV basis

As fed coal HHV basis only, energy value of feed steam and dryer fuel not included

Slag Handling

Slag formed in the coal gasification process flows to the bottom of the gasifier. This slag is quenched in a slag bath that is located within the gasifier vessel. Water is circulated through the slag bath to recover the heat from the slag. The hot slag water is cooled with a heat exchanger.

The cooled slag settles to a slag accumulator and lockhopper vessel. Once the slag has settled to the lockhopper vessel, the valves between the slag accumulator and lockhopper vessel are closed.

The lockhopper provides a transition between the pressurized gasifier and the atmospheric slag dewatering system. Once isolated from the gasifier, the lockhopper is depressurized and the

4-6

Process Description

valves are opened at the outlet of the lockhopper vessel. The slag and water mixture are then discharged to the slag dewatering system. This lockhopper system operates in batch mode continually to remove slag from the gasifier as it is accumulated.

The slag from the outlet of the lockhopper is dewatered using a submerged scraper conveyor.

The slag slurry water from the bottom of the submerged scraper conveyor is pumped to a clarifier where the clean slag slurry water is recycled to the lockhopper and the fines are collected and re-injected into the gasifier. The coarse slag from the outlet of the submerged scraper conveyor is conveyed to a slag storage pile. The coarse slag can then be landfilled or sold to market. The glassy, inert slag produced in the Shell gasifier is very low in carbon content which makes the slag attractive for sale.

Fly Ash System

After the syngas cooler, the syngas passes through first a cyclone and then ceramic candle filters that remove particulate matter (flyash) from the syngas. Similar to removing the slag from the gasifier, the flyash is removed from the cyclone and candle filter vessels with a batch process using lockhoppers. The coarse flyash that was removed by the cyclone can be recycled to the coal mill if it contains a significant amount of unconverted carbon. Otherwise, the coarse flyash along with the finer flyash collected by the candle filters is temporarily stored on site and either landfilled or sold to cement manufacturers or to other markets for flyash.

Syngas Wash Towers

Raw syngas flows from the candle filter to the syngas wash towers where the syngas is washed with water. The purpose of the water wash is twofold: 1) to recover any particulates that pass through the candle filters and 2) to recover chlorides that dissolve in the wash water and remove them from the system at concentration less than 300 ppm (to avoid corrosion of the carbon steel tower and piping). The wash water is primarily fresh demineralized water to which recycled water streams from the saturator water circulation loop (a purge stream) and the sour water stripper bottoms are added.

The water streams from the bottom of the syngas wash towers flow to a common system consisting of several operations:

• The first step is a flash at 7 psia. Liquid from the flash is cooled with make-up demineralized water used for syngas saturation before being filtered and sent to the cooling tower as makeup water.

• Solids recovered from the filtration mentioned above (particulates not removed by the candle filters) are sent to the coal pile. The amount of solids is estimated at only 110 lb/day.

• Vapor from the 7 psia flash is condensed under vacuum using an air cooler.

• Liquid condensed in the air cooler is separated from the small amount of vapor and is pumped to the sour water stripper.

4-7

Process Description

• Vacuum conditions in the condensate drum are maintained by a steam jet ejector. Effluent from the ejector flows to the sour water stripper.

This design was generated by Burns & McDonnell in absence of detailed design information by

Shell and does not represent Shell’s standard syngas scrubbing and sour water treatment design.

It is recommended that the design of this system be evaluated in detail in conjunction with Shell at a later development stage of the project.

The syngas wash system consists of the following equipment:

• Syngas wash tower (one tower for each of two parallel trains).

• Recovered water flash drum (one common drum for two parallel trains).

• Recovered wash water pumps (one common pump with a full spare for two parallel trains).

• Recovered wash water exchanger (one common exchanger for two parallel trains).

• Recovered wash water filters (one common filter with a full spare for two parallel trains).

• Flashed water condenser (one common air cooler for two parallel trains).

• Flash water condensate drum (one common drum for two parallel trains).

• Flashed water steam ejector (one common ejector for two parallel trains).

• Flashed water condensate pumps (one common pump with a full spare for two parallel trains).

Washed syngas flows to the COS/HCN hydrolysis reactors.

COS / HCN Hydrolysis

The syngas contains trace amounts of carbonyl sulfide (COS) and hydrogen cyanide (HCN) and relatively large amounts of both H

and H

O. Hydrolysis of COS is required because the AGR removal step (SELEXOL) only removes about 50% of the COS fed to AGR. The quantity of

COS present in the raw syngas is such that if not hydrolyzed the concentration of COS alone in the feed to the gas turbines would be 60 ppmv for the 100% PRB case and 480 ppmv for the 50%

PRB / 50% petcoke case compared to the required 30 ppmv level for COS plus H

S. The use of catalytic hydrolysis reduces the contribution of COS in the gas turbine feed gas to 1 ppmv and 5 ppmv for the 100% PRB and 50% PRB / 50% petcoke cases, respectively.

Hydrolysis of HCN occurs simultaneously with COS and effectively removes the HCN from the

GTG feed gas. Removal of HCN, which is a form of fuel-bound nitrogen, results in less NO x emissions from the gas turbines. The same catalyst is appropriate for both hydrolysis steps.

The COS and HCN are hydrolyzed according to the following reactions:

COS + H

O Æ H

S + CO

4-8

Process Description

COS + H

Æ H

S + CO

HCN + 2 H

O Æ NH

+ H

+CO

Sud-Chemie provided operating conditions that are expected to result in COS and HCN conversions greater than 99%.

Unconverted H

S along with other components in the tail gas from the TGTU are recycled and mixed with the syngas just upstream of the feed / effluent exchanger associated with the hydrolysis reactor. The feed gas to hydrolysis is further heated with high-pressure boiler feedwater just prior to entering the hydrolysis reactor to raise the temperature to the required level.

The COS and HCN Hydrolysis system consists of the following equipment:

• Hydrolysis interchanger (one exchanger for each of two parallel trains).

• Hydrolysis reactor (one reactor for each of two parallel trains).

After passing through the hydrolysis reactor, the syngas flows to syngas cooling and condensation.

Syngas Cooling and Condensation

The syngas is cooled prior to flowing to mercury removal in a set of three heat exchangers:

• Sweet syngas from AGR provides the heat sink for the first stage.

• Condensate from the surface condenser of the steam turbine provides the heat sink for the second stage.

• Cooling water provides the heat sink for the third stage.

Water condensed from the syngas is separated from the syngas and flows to the sour water stripper. Part of the condensate is recirculated to a point just upstream of the first stage of condensation to assure that the stream entering the condenser is partially liquid.

Primary equipment items included:

• Syngas interchanger (one exchanger for each of two parallel trains).

• First stage syngas condenser (one exchanger for each of two parallel trains).

• Second stage syngas condenser (one exchanger for each of two parallel trains).

• Water knockout drum (one drum for each of two parallel trains).

• Sour water pumps (one pump plus a full spare for each of two parallel trains).

4-9

Process Description

Mercury Removal

It is important that the temperature of the feed gas to mercury removal be above the dew point in order to avoid contamination of the carbon bed with condensed water. For this reason the saturated syngas from syngas cooling and condensation is heated to approximately 5°F above the dew point prior to flowing to the mercury removal beds.

Adsorbent beds are used to remove mercury from the syngas. One bed is provided for each train.

Information from NUCON was used as the basis for the study. A mercury removal of 90% or greater is expected. This adsorbent is an activated carbon made from coal.

The mercury removal system consists of the following equipment:

• Mercury removal preheater (one exchanger for each of two parallel trains).

• Mercury adsorbent bed (one vessel for each of two parallel trains).

• Mercury removal aftercooler (one exchanger for each of two parallel trains).

After passing through the mercury removal beds the syngas is cooled with cooling water prior to flowing to AGR.

Acid Gas Removal (AGR)

UOP’s SELEXOL AGR system is generally considered to be the standard for acid gas recovery from IGCC syngas. However, it was felt that the relatively modest sweet syngas sulfur specification (30 ppmv) and the low sulfur content of the PRB-only feed case might allow the use of other technologies. Amine treating was one technology considered. After discussion with

UOP it was determined that the 30 ppmv specification benefits both the SELEXOL and amine processes, and that for the operating pressure of this study SELEXOL will at least be competitive with, if not preferred to, amine absorption. Further, the use of SELEXOL lends itself to future

capture while amine treating does not. As a result of this analysis, amine treating was eliminated from further consideration for this study.

Another technology considered for the PRB-only, non-capture case was Sulferox. It was initially anticipated that the small sulfur recovery capacity needed (25 LTPD) would permit the use of a

Sulferox unit or similar redox technology in place of a SELEXOL AGR with Claus SRU and

SCOT-type TGTU. However, discussions with one vendor suggested that the best use of the redox unit would be as a replacement for the Claus/SCOT units. In this case the SELEXOL unit is still needed for acid gas removal. Another disadvantage of redox sulfur recovery is the relatively poor quality of sulfur product and additional handling and drying steps needed.

SELEXOL was subsequently chosen as the AGR technology for both the PRB-only and PRB-

PETCOKE cases for this study.

The SELEXOL solvent is a mixture of dimethyl ethers of polyethylene glycol. SELEXOL is a physical solvent, as compared to amines that form chemical complexes and require more energy to regenerate. SELEXOL solvent is chemically inert and is not subject to the same corrosion and degradation problems as amines.

4-10

Process Description

SELEXOL solvent has a higher affinity for H

S than CO

. This allows a SELEXOL system to achieve a very high rejection of H

S from the syngas, to meet the specification of less than 30 ppm of H

S + COS in the treated syngas, while allowing a controlled “slip” of CO

depending on the design requirements. Slip is defined as the percentage of CO

that leaves the system with the sweet syngas compared to the CO

in the feed to SELEXOL. CO

slip sets the concentration of

S in the acid gas product from the SELEXOL unit. Very high acid gas concentrations (greater than 50% H

S) require large, costly equipment and solvent circulation rates. Very low concentrations (less than about 25% for an oxygen-blown SRU that is also burning sour water stripper gas) complicate downstream SRU design and operation.

For each of the feed cases, UOP was asked to provide SELEXOL unit material balances and equipment lists for 25% and 50% H

S acid gas products. The information provided by UOP was evaluated and, based on this evaluation, acid gas concentrations of 25% and 50% H

S were selected for the PRB and PRB-PETCOKE cases, respectively. Although these are not completely optimized selections, they are believed to give reasonable estimates of capital and operating costs for the two cases.

SELEXOL consists of absorber and stripper towers, stripper reboiler, rich/lean solvent exchanger and flash drums typical for such systems. A simplified process flow diagram for SELEXOL is presented in Figure 4-3.

4-11

Process Description

Figure 4-3

SELEXOL Process Flow Diagram

The lean SELEXOL solvent is chilled using refrigeration to optimize the solvent circulation rate and energy input. Low pressure steam is used to supply heat to the stripper reboiler.

Primary equipment items included:

(Note: The AGR unit is a single train serving both gasifier trains.)

• H

S absorber.

• H

S stripper with reboiler, condenser, reflux drum and pumps.

• Rich flash coolers and drum.

• Lean / rich exchanger.

• Lean solvent chiller.

• Rich flash compressor.

• Refrigeration package.

4-12

Process Description

Sulfur Recovery and Tail Gas Treating

A block flow diagram of the SRUs and TGTU is shown in Figure 4-4. Acid gases from the AGR unit and from the sour water stripper (SWS) unit are treated in two parallel Claus SRUs to destroy hydrogen sulfide and ammonia. Tail gas from the two SRUs is combined and fed to a single TGTU to convert residual sulfur dioxide from the Claus process back to hydrogen sulfide before it is compressed and recycled to the COS Hydrolysis sections of the gas cooling trains.

To minimize the volume of recycle gas all of the oxygen required for SRU operation is supplied at 95% purity by the ASU. A thermal oxidizer is included to handle vent streams from the sulfur pits and truck/rail loading facilities.

Figure 4-4

Block Flow Diagram – Sulfur Recovery and Tail Gas Treating

Approximately 96% of the sulfur in the acid gas feeds is recovered in one pass through the

SRUs. By recycling the remaining hydrogen sulfide back through the gas cooling trains overall sulfur recovery from the syngas streams is increased to over 99%.

Sulfur Recovery Units (SRU)

Hydrogen sulfide is destroyed to form sulfur byproduct in Claus-technology SRUs. H

2 converted to sulfur according to the Claus reaction:

S is

S + SO

↔ (3/n)S n

+ 2H

Sulfur dioxide is generated by reacting part of the H

2 thermal reactor:

S in the acid gas feed with oxygen in a

S + 1.5O

↔ SO

+ H

4-13

Process Description

The 2:1 mixture of SO

and H

S is then passed through a series of catalytic reactor stages to facilitate the Claus reaction. Sulfur is removed after each step by condensing it out of the vapor phase.

Sour water stripper gas is also fed to the SRUs for the purpose of ammonia destruction.

Ammonia is destroyed in the thermal reactor by either combustion or dissociation:

2NH

+ 1.5O

↔ N

+ 3H

2NH

• N

+ 3H

To destroy ammonia, the thermal reactor must operate above 2300-2400°F. For the 100% PRB case, the AGR acid gas feed contains only 25% hydrogen sulfide. As a result the heat content of the stream is very low. Part of the AGR acid gas stream must be bypassed around the thermal reactor and the remaining AGR acid gas must be preheated to achieve the high temperature needed for ammonia destruction. This is referred to as a split-flow SRU, and is a common application of the technology. For the 50% PRB / 50% petcoke, the AGR acid gas feed contains

50% hydrogen sulfide. The heat content of the stream is high enough to produce the necessary temperature without bypassing or preheating.

Waste heat boilers downstream of the thermal reactors produce saturated 600 psia steam. Part of the steam is used to heat the feeds to the catalytic reactor stages. The remainder is exported to the steam cycle for power generation. Each SRU has three stages of sulfur condensation, reheat and catalytic reaction. Low-level steam is produced in the sulfur condensers and exported to the steam cycle.

Tail gas from the final sulfur condenser goes to the Tail Gas Treating Unit. Elemental sulfur produced by the SRU is collected in a sulfur pit (sump). From there, the sulfur is pumped to the railcar loadout facility for transportation off-site.

Two 50% SRU trains are included in the estimate. Primary equipment items included for the

SRU trains are:

• AGR acid gas knockout drum (one for each train).

• AGR acid gas knockout drum pumps (one operating pump with one full spare for each train).

• AGR feed heater (PRB-only case, one for each train).

• Sour water stripper acid gas knockout drum (one for each train).

• Sour water stripper acid gas knockout drum pumps (one operating pump with one full spare for each train).

• Combustion air startup blower (one for each train).

• Thermal reactor and acid gas burner (one for each train).

• Waste heat boiler (one for each train).

• Sulfur condenser (one for each train).

4-14

Process Description

• Reheat exchangers (three for each train).

• Catalytic reactor vessel (one vessel with three compartments for each train).

• Final sulfur condenser (one for each train).

• Low-pressure steam condenser (one for each train).

• Sulfur pit (one for each train).

• Sulfur transfer pumps (one operating pump with one full spare for each train).

• Sulfur railcar loadout facility.

Tail Gas Treating Unit (TGTU)

The TGTU for this study consists of a catalyzed hydrogenation reaction step that converts residual sulfur dioxide back to hydrogen sulfide, followed by gas cooling. There is normally ample hydrogen and carbon monoxide present in the SRU tail gas for the reduction reaction.

However, if additional hydrogen is needed to feed the tail gas reactor, syngas can be added upstream of the reactor.

The tail gas reaction is:

+ 3H

↔ H

S + 2H

Gas cooling includes a waste heat steam generator followed by direct contact with water in a packed quench tower. The small amount of water condensed in the quench tower is exported to the sour water stripper unit.

The amine absorber and regenerator that are typically attached to TGTUs for hydrogen sulfide recovery are not required in this service, since the tail gas is recycled to the gas cooling trains.

This eliminates a source of H

S/SO

emissions and improves recovery of carbon monoxide and hydrogen for power generation.

A single TGTU services both SRUs. The TGTU consists of the following equipment:

• Tail gas feed heater.

• Tail gas hydrogenation reactor.

• TGTU waste heat boiler.

• Quench tower.

• Quench water pumps (one operating pump with one full spare).

• Quench water air cooler.

• Quench water trim cooler.

4-15

Process Description

Tail Gas Compression

Multistage reciprocating compressors are required to boost treated tail gas to the pressure required for recycle to the gas cooling trains. Two full-capacity compressors with interstage knockout drums are provided for reliability.

A net production of carbonyl sulfide is anticipated through the SRUs and TGTU due to reactions of sulfur compounds with carbon monoxide and carbon dioxide. As a result, the tail gas must be recycled to a point upstream of the COS hydrolysis section. A small quantity of sour water is created as the tail gas is compressed. This water is exported to the sour water stripper unit.

Thermal Oxidizer

Purging of sulfur pit vapor spaces and vent recovery from sulfur loading operations will create vent streams containing mixtures of air and hydrogen sulfide. These vent streams are incinerated in the thermal oxidizer.

Sour Water Stripping

The sour water stripper receives feed from four sources:

• Vapor from the steam jet ejector associated with the system for handling the bottoms stream from the water wash towers.

• Condensate from the 7 psia flash of the bottoms stream from the water wash towers.

• Sour water from the knockout drums associated with syngas cooling and condensing.

• Sour water from the TGTU associated with sulfur recovery.

Water from the bottom of the sour water stripper joins the demineralized water and saturator purge water streams and flows to the top of the water wash towers. A pump-around loop with an air cooler provides condensing at the top of the sour water stripper. Low pressure steam serves as the heat source for the reboiler of the sour water stripper. Gas containing primarily H

S and ammonia, with lesser amounts of CO and H

, from the top of the sour water stripper is sent to the

SRU.

Primary equipment items included in the sour water stripper are:

• Sour water feed/effluent exchanger (one common exchanger for two parallel trains).

• Sour water stripper (one common tower for two parallel trains).

• Sour water pump around pumps (one common pump with a full spare for two parallel trains).

• Sour water pump around cooler (one common air cooler for two parallel trains).

• Sour water reboiler (one common exchanger for two parallel trains).

4-16

Process Description

Syngas Saturation

Sweet syngas from the AGR, after exchanging heat with the sour syngas in the first condensing stage, flows to the syngas saturators. The purpose of the saturators is to add vaporized water to the syngas to bring the moisture content to 16.5 mole % for NO x

reduction, which also results in additional mass flow through the turbine section (i.e. more power). The wet syngas is further preheated with high-pressure (HP) boiler feedwater to raise the temperature to 405°F before serving as fuel for the gas turbines.

Demineralized water, after heat exchange with the recovered water from the water wash towers, is fed to the circulating loops of the syngas saturators in amounts required to achieve the desired moisture content of the syngas. A small purge stream from the circulating loops joins the other water streams that flow to the top of the water wash towers. This avoids buildup of any components in the water that do not vaporize.

Water in the circulation loops is heated with HP boiler feedwater as required to maintain the level in the bottom of the syngas saturators, thus assuring that the water added to the loop is vaporized and added to the syngas.

Primary equipment included for syngas saturation is as follows:

• Syngas saturator (one tower for each of two parallel trains).

• Saturator heater (one exchanger for each of two parallel trains).

• Saturator circulation pumps (one pump plus a spare for each of two parallel trains).

• Sweet syngas heater (one exchanger for each of two parallel trains)

After passing through the syngas saturators, the syngas is ready for use in the power block.

Power Block Description

The power block of the IGCC consists of the gas turbines, HRSGs, steam turbine, condenser, and interconnecting pipe, pumps, etc. as required for the power production duty. The power block of an IGCC is very similar to that of a standard combined cycle.

Gas Turbines

The Project consists of two GE PG7251FB (7FB) gas turbines rated at 232 MW each on syngas.

Like a conventional combined cycle or gas turbine plant, ambient conditions (in particular compressor inlet temperature) can greatly affect the performance of an IGCC facility. A gas turbine is a constant volume machine, therefore, lower compressor inlet temperatures result in greater air density, which results in more power output and decreased heat rate. Similarly, higher ambient temperatures result in lower air density, which results in lower output and higher heat rate.

4-17

Process Description

Because of the low heating value of the syngas, the fuel mass flow through the gas turbine is significantly higher than a standard natural gas fired turbine (approximately 4 times greater).

This additional mass flow, coupled with the additional nitrogen mass flow for NO x

control, increases the gas turbine output over that of a conventional gas turbine firing natural gas. This causes the gas turbine to reach its shaft limit at a higher ambient temperature than it typically would. Therefore, the gas turbine output must be limited to avoid exceeding the shaft limit of the turbine (232 MW for the 7FB). This is accomplished by extracting a portion of the air from the compressor section of the gas turbine for gas turbine compressor inlet temperatures (CIT) below ~70°F. This compressed air is utilized in the ASU, which reduces the additional auxiliary load of compression required by the ASU compression system. At CITs above ~70°F, the air density is low enough that the total mass flow through the turbine does not result in sufficient

MW to exceed the shaft limit of the gas turbine. Thus air extraction from the compressor section of the gas turbine is not available for ASU use at CITs above ~70°F. Exporting of air from the

GTG to the ASU is referred to as air-side integration.

Since air-side integration improves the efficiency of the IGCC facility, it is beneficial to export as much air as possible to the ASU. Therefore, 85% effective evaporative cooling is included on the inlet to each gas turbine to lower the compressor inlet temperature, resulting in improved mass flow available for the turbine and the ASU.

Alternatively, inlet air chilling could be used to further reduce the CIT. Inlet air chilling has a higher capital cost than evaporative cooling and may not be economically justified since this equipment will not be fully utilized for a significant portion of the year. It is recommended that further studies regarding inlet air cooling methods and tradeoffs be pursued.

Heat Recovery Steam Generators (HRSG)

Two HRSGs are utilized to capture the gas turbine exhaust heat. Triple pressure, naturalcirculation HRSGs are utilized to preheat feedwater, generate steam, and superheat both the steam generated within the HRSG and the saturated steam from the gasification process. The

HRSGs also utilize a reheat section to further increase steam cycle efficiency.

Alternatively, two-pressure HRSGs could be utilized in lieu of three-pressure HRSGs, thus eliminating the LP evaporator and superheater sections of the HRSG. The loss of the LP section would result in reduced steam flow to the STG (i.e. less output), however since very little LP steam is being generated in the HRSG (particularly for the 100% PRB cases), this increased capital (approximately $5 million), may not be justified. Alternatively, a large amount of LP steam is generated in the CO

capture case (Chapter 13), which is of great benefit in that scenario. Further analysis into the use of a two-pressure HRSG should be performed in the future.

Steam Turbine

The total steam is expanded in a steam turbine to generate power. The steam turbine consists of three turbine sections (HP, IP, LP), utilizing a dual down flow LP turbine exhaust. The steam from the low pressure turbine exhaust is condensed by the heat rejection system.

4-18

Process Description

The design pressure is 1905 psia with 1050°F main steam and hot reheat temperatures. The turbine will drive a hydrogen-cooled electric generator.

Steam Condenser

The water-cooled steam condenser will be a single, rectangular shell, single pressure, split waterbox, two pass steam condenser. The water-cooled condenser will include an air removal section and baffled steam inlet connections for the 100% steam turbine bypass. Air removal from the condenser’s upper portion will be via two full capacity vacuum pumps. To dissipate the energy in the condensing steam, a circulating water system will supply cooling water from the wet cooling tower to the water-cooled steam condenser. The steam condenser is designed with a

5°F terminal temperature difference (TTD) and a 17°F range at the 73°F ambient condition.

Steam System

The steam system transports main steam (HP), reheat steam, intermediate pressure (IP) steam and low pressure (LP) steam between the HRSGs and steam turbine. A steam turbine bypass system is included to accommodate the steam generated by the HRSG during start-up of the gas turbine before steam turbine admission, as well as during a full-load steam turbine trip.

Condensate System

The condensate system delivers condensate via two, 100% capacity vertical, condensate pumps.

These pumps transport condensate from the steam condenser hotwell, through the gland steam condenser to the low pressure HRSG drum.

Feedwater System

The feedwater system provides feedwater to the HP and IP HRSG economizers, gasifier and syngas cooler via two 100% capacity, HP/IP boiler feed pumps per HRSG. This system also supplies desuperheating water requirements for the HRSGs and steam turbine bypass system.

Natural Gas System

The natural gas system provides pipeline quality natural gas to the gasifier and auxiliary boiler for startup and the gas turbine for backup fuel. It is assumed that the natural gas is available at the site boundary at sufficient pressure (~570 psig) to avoid the need for compressors.

4-19

Process Description

Balance of Plant

Coal Handling

Fuel delivery to the site is accomplished by rail. A rotary car dumper is provided for unloading of the coal. The coal handling system provides for the stackout, storage, and reclaim of the solid fuel for this project. Outdoor storage is assumed at this stage of the project. Layout drawings provided in Appendix B help to illustrate these systems.

100% PRB Option

The coal handling system unloads the coal with a rotary car dumper and conveys the coal with a stockout conveyor to the stockout pile. From the stockout pile, coal is moved with mobile equipment to long term storage or to the reclaim system. The reclaim system consists of a hopper, belt feeder, reclaim tunnel, and dust collection. The reclaim system supplies the coal to the inlet of the coal drying and milling equipment supplied with the gasifier.

Because PRB is shipped long distances, 60 days of long term PRB storage is provided to lessen the possibility of fuel interruption.

50% PRB / 50% Petcoke Option

The coal handing system for the fuel blend case is similar in concept to the 100% PRB option.

The stockout conveyor has an intermediate transfer tower that allows for stockout into one of two piles. Weight feeders on the reclaim system allows for accurate blending of the fuel prior to the coal drying and milling equipment. Each fuel has its own stockout pile and reclaim system.

Similar to the 100% PRB option, 60 days of long term PRB storage is included. Petcoke is produced locally, thus reducing the potential for supply interruption, thus only 30 days of petcoke storage is provided.

Cooling System

Cooling for the condenser, ASU, and other auxiliary cooling loads is accomplished by a multicell, counter flow, mechanical draft, wet cooling tower. Circulating water is transported between the water-cooled steam condenser and cooling tower by two 60% capacity circulating water pumps. Additionally, two 60% capacity auxiliary cooling water pumps are used to supply auxiliary cooling water to the ASU, and other auxiliary cooling loads.

The cooling system is designed with a 2°F recirculation allowance and an 11°F approach (wet bulb minus cold water temperature).

4-20

Process Description

Auxiliary Boiler

A natural gas fired package boiler (approximately 200,000 lb/hr @ 150 psig) is included for preheat of the gasification area heat exchangers and providing steam to the critical systems during plant startup. Since this system is only required during startup sequence procedure, it is anticipated to be used less than 200 hours per year.

Buildings

The IGCC facility has the following major buildings:

• Administration and control room building.

• Water treatment building.

• Warehouse.

• Auxiliary boiler.

• Yard maintenance building.

• Cooling tower chemical building.

Water Treatment

Water mass balances are provided in Appendix C. Consumptive water uses include potable/sanitary water, plant service water, demineralized water, cooling tower make-up, and fire water. Raw water for the site is based on the wells with water quality shown in Table 4-3.

4-21

Process Description

Table 4-3

Assumed Raw Water Quality

Data Type Data Units

uS/cm

Specific Conductance 607

Hardness 224 mg/L as CaCO

Calcium

Magnesium

Sodium

Potassium

Chloride

Sulfate

15 mg/L as Ca mg/L as Mg mg/L as Na mg/L as K mg/L as Cl mg/L as SO

Silica pH

Fluoride

Total Alkalinity

36 mg/L as SiO

7.5

0.4

mg/L as Fl

189 meq/L as CaCO

Raw water supply and wastewater discharge requirements (on a local, state, and federal level) vary greatly from location to location. Once more information is known about that anticipated project site, additional studies should be performed to verify raw water availability and wastewater discharge viability for the project. These issues have the potential to greatly impact the cost and performance of the project.

Raw Water/Service Water

Raw water from the on-site wells is routed to an on-site raw water storage pond that stores 30 days of raw water. This storage pond may not be required if a highly reliable source of water is available, however most Owners of large coal generating stations are incorporating some amount of raw water storage to hedge against potential shortfalls in water availability. From the raw water pond, the water is routed to the raw water treatment where the majority of suspended solids, iron, and manganese will be removed by filtration and sodium hypochlorite injection prior to entering the service water storage tank (which also serves as the firewater storage tank).

Service water uses include coal pile dust suppression, gasifier slag quenching, pump seals, equipment wash water, fire water, and other miscellaneous sources.

The raw water also serves as the major source cooling tower make-up (along with demineralizer reject, and Gasifier and HRSG blowdown). The cooling tower requires water treatment chemistry and blowdown to prevent scale and biological formation and corrosion on piping and heat transfer surfaces.

4-22

Process Description

Demineralized Water

Raw water is routed to the demineralizer system that consists of reverse osmosis and electrodeionization (EDI) equipment designed to produce high purity water for various uses in the gasifier and HRSG. Reject from this system is routed to the cooling tower as an additional make-up source. The demineralized water is stored in a demineralized water storage tank.

Wastewater

Blowdown from the cooling tower, coal pile wastewater, reject from the raw water treatment, and clean effluent from the plant drains are routed to a common wastewater collection pond prior to discharge to a nearby river.

Sanitary Drains

Plant sanitary drains are routed to an on-site septic system.

Flare

A flare system is included to burn off syngas produced the by gasifier during startup or in the event of a unit trip or pressure excursion. The flare is located at a safe distance (600 ft. radius) from accessible areas. A perimeter fence is placed around the flare to prevent people and animals from approaching the flare.

A 200 ft. tall guyed flare with a 60 in. flare tip is provided in the estimate. A knockout drum and pumps are included upstream of the flare.

Fire Protection

Fire protection water is supplied from the raw water storage tank with an electric motor driven fire pump, a diesel engine driven fire pump and an electric motor-driven jockey pump. Fire protection and detection systems will be in accordance with NFPA requirements. A fire water loop with sectionalizing valves is included around the plant. Automatic and semi-automatic fire protection systems employing detection and extinguishing equipment and hose stations are included for the generator step-up transformers, steam turbine lube oil system, cooling tower, buildings, Gasification Systems, and coal handling and storage. Fire hydrants, monitors, and fire extinguishers will be strategically positioned throughout the plant for coverage of fuel conditioning equipment, cooling tower fan deck, steam turbine, gas turbine, and gasificationrelated areas. The gas turbine fire protection system is supplied with the equipment. The fire detection system will provide detection throughout the plant and annunciation in the main plant control room.

4-23

Process Description

Plant Drains

The plant drains system collects liquid waste (non-sanitary) from plant areas and equipment and transfers the waste to the wastewater treatment system. This system includes sumps and two

100% capacity pumps for each sump. Equipment drains will be located adjacent to all equipment requiring intermittent or continuous drainage during operation or shutdown. Plant drains with potential oil contamination will be drained to the oil-water separator.

Electrical Systems

The electrical systems for the IGCC facility consist of the auxiliary power supply, generator feed, switchyard, essential AC and DC power supply, and freeze protection systems.

Auxiliary Power Supply

The auxiliary power system provides electric power for all systems in the plant.

The power distribution for the power block and gasifier plant is supplied from the main 13.8kV distribution switchgear. The main 13.8kV distribution switchgear is supplied from two plant auxiliary power transformers that are connected to the low side of the gas turbine GSU transformers that are connected to the 345kV substation.

The main 13.8kV distribution switchgear supplies the following 4.16kV switchgear lineups located in the power block and throughout the plant. Each of the 4.16kV buses is located in a power control module (PCM) placed in the vicinity of the loads.

• Power block switchgear A.

• Power block switchgear B.

• Coal handling switchgear.

• Gasification switchgear.

• Balance of plant bus.

• Sulfur & slag bus.

Each of the 4.16kV switchgear lineups supplies multiple station service transformers that supply

480V load centers arranged in a main-tie-main configuration. The load centers supply the 480V motor and non-motor loads. The 480V motor loads are supplied from motor control centers

(MCC) that are connected to the 480V load centers. The 480V load centers and 480V MCCs are located in the PCM buildings along with the 4.16kV switchgear lineup. The station service transformers are located outside the PCM buildings. The small power loads are supplied from

120/240-volt utility panels located in the PCM.

4-24

Process Description

The power distribution for the ASU is supplied from the ASU 13.8kV distribution switchgear.

The ASU 13.8kV distribution switchgear is supplied from two auxiliary power transformers that are connected to a single overhead line from the 345kV substation. Each auxiliary power transformer connects to a 13.8kV switchgear bus that supplies the ASU compressor motors and a

13.8kV to 480V station service transformer. The station service transformers connect to 480V switchgear buses that are interconnected with tie breakers.

A plant emergency generator is connected to the 4160 volt bus. The natural gas engine-generator is sized to start and operate the emergency loads of the facility.

Generator and Excitation

The generator system provides power from the gas turbine and steam turbine generators to the generator step-up transformer.

The generator system consists of the following:

• Auxiliary transformer.

• Isolated phase bus.

• Generator step-up transformer.

• Protection devices.

• Wiring, instrumentation, and controls.

The excitation system provides controlled DC power to the generator field. The exciter system consists of the following:

• Power potential transformer (PPT) that is connected to the generator terminals with an isolated phase bus tap. The power potential transformer steps down the generator voltage for use by the exciter.

• Static exciter system supplied by the turbine manufacturer. The exciter systems convert the AC power for the PPT to a DC power source applied to the generator rotor to establish the generator field. The system controls the generator field current to regulate the generator terminal voltage, power factor, or VAR flow.

Switchyard

The switchyard configuration is a three-bay breaker-and-a-half arrangement consisting of 9 breakers. The switchyard has dedicated positions for each generator step-up transformer, two incoming transmission lines, and on-site transmission to the ASU.

4-25

Process Description

The high-voltage equipment is rated for 345kV nominal operating voltage.

Essential AC and DC Power Supply

The essential AC and DC power system provides highly reliable power to such essential low power loads as DCS, logic systems, annunciators, events recorder, data loggers and computers, communications equipment, intercommunications systems and emergency lighting. Essential power for the gas turbine and its auxiliaries is provided by gas turbine manufacturer as part of the gas turbine package.

Separate plant uninterruptible power supply (UPS) systems are provided for the power block and

Gasification System. The equipment for the essential power supply consists of:

• DC chargers and batteries.

• Operator terminals.

• DC switchboard.

• Single phase UPS.

• Electrolytic capacitors.

• Wire, instrumentation, and controls.

Freeze Protection

The freeze protection system maintains temperature above the freezing point in piping and equipment. The freeze protection system consists of

• Heat tracing cable.

• Voltage monitors.

• Thermostats.

• Contactors.

• Control cabinets.

4-26

TERMINAL POINTS

General

The following terminal points identify the termination points or interfaces for those services or facilities, which extend beyond the scope of the work included in this report.

Site Access

Site access roads shown on the layout drawings in Appendix B are included in the capital cost estimate. Any roads or road upgrades to the site are not included in the estimate.

Rail Siding

The capital cost estimate includes a 5 mile rail siding to the site plus the track shown on the layout drawings in Appendix B. It is assumed that all large equipment is delivered to the site via rail. Heavy haul costs are included to offload the equipment from the rail to the foundations.

Modifications to any existing rail or road infrastructure are not included.

Sanitary Waste

Sanitary waste is disposed of in an on-site septic system.

Natural Gas

The capital cost estimate includes one mile of 12 in. natural gas pipeline to the site for startup and backup fuel. Additionally, Burns & McDonnell’s estimate includes natural gas metering and pressure regulation equipment. It is assumed that natural gas will be supplied by others at sufficient pressure (~570 psig), temperature, quality, and flow to meet the requirements of the

IGCC facility without the need for natural gas compression or dew point heating.

Raw Water Supply

Raw water is assumed to be available through on-site wells. The capital cost estimate includes the well water system. If well water is unavailable or other sources of water are required to supplement the well water supply, the costs of these items are by others.

5-1

Terminal Points

Wastewater Discharge

Wastewater is assumed to be discharged to a river through a wastewater pipeline 5 miles in length after being treated in the on-site wastewater treatment pond. The capital cost estimate includes the cost of the wastewater pipeline and on-site wastewater treatment pond. Any other means of wastewater discharge is outside the scope of this estimate.

Electrical Interface

The project capital cost estimate includes the electrical interconnection costs up to and including the plant switchyard. Transmission lines to the site or transmission upgrades are by others.

5-2

IGCC PERFORMANCE ESTIMATES

Performance Estimate Assumptions

The following assumptions are used as the basis for the performance estimates:

• Output and heat rate estimates are at new and clean conditions.

• An 85% effective evaporative cooler is included and is on for the 93°F case.

• Performance is based on an elevation of 100 ft.

• Performance is based on the fuel analysis provided in Table 3-1.

• Gas turbine performance and Shell gasification performance estimated by EPRI without vendor involvement.

• Steam turbine consists of three turbine sections (HP, IP, LP) with a dual down flow exhaust. The design throttle conditions are 1905 psia with 1050°F main steam and hot reheat temperatures.

• Air-side integration is used to supplement air flow to the ASU when the gas turbine has reached its shaft limit (for CIT below ~70°F).

• Performance is based on a wet cooling tower.

Performance Estimate Results

The results of the performance analysis are provided in Table 6-1. Heat balance diagrams containing additional information are provided in Appendix F.

6-1

IGCC Performance Estimates

Table 6-1

IGCC Performance Summary

Ambient Dry Bulb Temperature, °F

Ambient Wet Bulb Temperature, °F

Elevation, ft.

Evaporative Cooling, On/Off

Coal Heat Input, MMBtu/hr (LHV)

Coal Heat Input, MMBtu/hr (HHV)

Gas Turbine Gross Output, MW (each)

Gas Turbine Gross Output, MW (total)

Steam Turbine Gross Output, MW

Gross Plant Output, MW

Auxiliary Load

Power Block, MW

Material Handling, MW

Air Separation Unit, MW

Gasifier, MW

Compression

Syngas Treatment, MW

Total Plant Auxiliary Load, MW

Net Plant Output, MW

Net Plant Heat Rate, Btu/kWh (LHV)

Net Plant Heat Rate, Btu/kWh (HHV)

Plant Cooling Requirements, MMBtu/hr (Total)

Steam Cycle Cooling Requirement, MMBtu/hr

BOP Auxiliary Cooling Requirement, MMBtu/hr

Total Makeup Water Requirement

GPM

Acre-ft/year (@ 85% CF)

599.2

8,390

9,090

2,155

1,550

605

22.5

6.3

101.3

2.3

0.0

5.0

137.4

100

Off

5,026

5,447

232.0

464.0

272.6

736.6

4,390

6,830

100% PRB

100

Off

4,705

5,099

224.9

449.7

260.1

709.9

553.0

8,510

9,220

2,141

1,480

661

22.0

5.9

122.1

2.1

0.0

4.7

156.8

4,980

6,830

528.4

8,630

9,350

2,159

1,450

709

21.8

5.8

119.1

2.0

0.0

4.5

153.2

100

4,559

4,940

215.6

431.2

250.4

681.5

5,580

6,830

597.0

8,560

8,950

2,185

1,540

645

22.0

4.5

101.1

2.2

0.0

7.4

137.2

100

Off

5,113

5,343

232.0

464.0

270.1

734.2

50% PRB / 50% Petcoke

100

Off

4,800

5,016

226.3

452.7

258.4

711.1

100

4,655

4,864

217.0

433.9

248.7

682.6

4,619

7,170

553.0

8,680

9,070

2,179

1,480

699

21.9

4.3

122.9

2.1

0.0

6.9

158.0

5,231

7,170

528.2

8,810

9,210

2,206

1,460

746

21.6

4.1

120.0

2.0

0.0

6.7

154.5

5,800

7,170

The power block auxiliary load includes gas turbine auxiliary loads, steam turbine auxiliary loads, power block pumping loads, transformer losses, iso-phase bus losses, and miscellaneous

BOP auxiliary loads (lighting, HVAC, air compression, etc.). Additionally, the power block auxiliary loads include the cooling water pumps and cooling tower that provide the cooling loads for the entire facility.

Material handling auxiliary loads include the loads associated with coal conveying and coal milling and drying equipment.

Air separation unit auxiliary loads include the main air compressor, booster air compressor, cold box, nitrogen compression, cryogenic pumping, and miscellaneous ASU auxiliary loads.

Gasifier auxiliary loads include recycle quench gas compressor loads and slag handling loads.

Syngas treatment auxiliary loads include AGR, SRU, TGTU, and miscellaneous process loads.

6-2

IGCC CAPITAL COST ESTIMATES

Capital Cost Estimate Assumptions

• All estimates are “screening level” in nature and do not reflect guaranteed costs (+/- approximately 30%).

• Project is based on a greenfield site.

• Project cost is based on the terminal points as defined in Chapter 5.0.

• It is assumed that 10 ft. of cut is required for half the site area and 10 ft. of fill is required for the other half of the site area. Other areas may require more cut and fill, however an average cut/fill of 10 ft. is assumed. Additionally, it is assumed there are no existing structures, underground utilities, or hazardous materials on site.

• Project costs are based on a preliminary site layout drawings included in Appendix B.

• Project costs are based on preliminary electrical one-line diagrams included in Appendix

• Preliminary foundation design is based on the assumption that shallow, mat-type foundations will be sufficient for all minor foundations. Major structures such as the gas turbines, HRSGs, steam turbine, step up transformers, gasifiers, and the major equipment for the ASU, AGR, SRU, TGTU, and coal reclaim are assumed to require piling.

• The steam turbine, gas turbines, and HRSGs are located outdoors.

• Sufficient area to receive, assemble, and temporarily store construction materials is available.

• The design fuel is based on the information provided in Table 3-1.

• An on-site landfill is included for disposal of flyash and slag. The capital cost estimate includes the initial 5-year cell. The ongoing cost of closing current cells and the addition of future cells is covered in the landfill cost ($/ton) used in the O&M estimate.

• Cooling is achieved through the use of conventional wet cooling towers.

7-1

IGCC Capital Cost Estimates

• Construction costs are based on an engineer, procure and construct (EPC) contracting philosophy. The Owner would have an EPC contract with a single “Global EPC” contractor. It is assumed the Global EPC contractor will contract the ASU, gasification, and syngas treatment as separate EPC contracts (under the Global EPC). The Global

EPC contractor is responsible for integration of the construction and design aspects of all

EPC contractors and assumes overall risk for schedule, performance, and capital cost.

• Labor rates are based on prevailing wage rates and productivity factors for the Texas Gulf

Coast. Labor rates include a $9/hour per diem to account for non-local labor (assumed

90% outside 50 miles).

• All capital cost estimates are in mid-2006 dollars and do not include escalation through the COD, sales tax, interest during construction, financing fees or transmission lines/upgrades.

Indirect Construction Costs (Included in EPC Cost)

The following project indirect costs are included in the EPC capital cost estimate:

• Construction water and power.

• Performance testing and CEMS/stack emissions testing (where applicable).

• Initial fills and consumables, preoperational testing, startup, startup management, and calibration.

• Construction/startup technical service.

• Heavy haul

• Site surveys and studies.

• Engineering and construction management.

• Construction testing.

• Operator training.

• Startup spare parts.

• Performance and payment bond.

• EPC contingency.

• EPC Fee.

7-2

IGCC Capital Cost Estimates

Owner Indirect Costs

In addition to the estimated EPC costs, an estimate of anticipated Owner’s costs was also provided. The Owner’s costs included in the estimate are as follows:

• Project development costs.

• Owner project management and project engineering (including startup).

• Owner’s operations personnel prior to COD.

• Owner’s construction management.

• Owner’s engineer.

• Permitting and licensing fees.

• Land (1,500 acres for accommodation of future expansion to 3 x 550 MW units).

• Political concessions / area development allowance.

• Startup consumables, including fuel.

• Credit for test power sales.

• Initial fuel inventory (60 days PRB, 30 days petcoke).

• Builder’s risk insurance.

• Site security.

• Owner’s legal costs.

• Operating spare parts.

• Permanent plant equipment and furnishings.

• Owner’s contingency (5% of entire project cost).

7-3

IGCC Capital Cost Estimates

Costs not included

The costs not included in the capital costs estimates include, but are not limited to the following:

• Escalation through COD is not included. The EPC and Owner’s costs provided are in overnight 2006 US dollars. This cost does not represent the cost of an EPC contract signed today. It represents the cost of the project assuming zero time value of money.

Additional escalation needs to be applied by the Owner as a part of the Owner’s

Integrated Resource Plan to determine when the project would fit into the generation needs of the Owner.

• Sales Tax is not included. Because sales tax requirements differ greatly depending on location (even within a state), sales tax has been excluded from this estimate. In some instances, emissions controls equipment have been known to be tax exempt, so it is possible that a large part of the IGCC facility may be tax exempt, if not all. Additionally, some municipalities or utilities are tax exempt. If this project proceeds and a site is chosen, it is recommended that a detailed investigation into sales tax be pursued at that time.

• Interest during construction is not included in the capital cost estimates provided herein.

Since the estimates provided are in overnight 2006 US dollars, applying interest during construction is not feasible. However, interest during construction costs are a very significant project cost that must included separately once a desired COD is determined, which will increase the overall capital cost of the project. Interest during construction is included in the 20-year levelized busbar cost ($/MWh) discussed in Chapter 12.

• Financing fees are not included in the capital cost estimates provided herein. However, financing fees are included in the 20-year levelized busbar cost ($/MWh) discussed in

Chapter 12.

• Transmission lines to or from the site are not included. Additionally, transmission upgrades, if required, are not included.

Capital Cost Results

The estimated capital costs for the project are provided in Table 7-1. Additional cost detail can be found in Appendix E.

7-4

IGCC Capital Cost Estimates

Table 7-1

IGCC Capital Cost Estimate Summary (2006 US Dollars)

Procurement

Gas Turbines

Steam Turbine

HRSGs

Other Mechanical

Electrical

Water & Chemical Treatment

Structural

Construction

Furnish and Erect

Material Handling

Air Separation Unit and N2 Storage

Gasification

Syngas Treatment

GTG/STG/HRSG Erection

Civil / Structural Construction

Mechanical Construction

Electrical Construction

EPC Contractor Indirect Costs

Construction Indirects

Construction Management

Pre-operational startup and testing

Other

Project Indirects

Project Management and Engineering

EPC Contingency

EPC Fee

Other

Total EPC Contractor Cost (2006 US $)

Owner Indirect Costs

Owner's Engineer

Permitting and Licensing Fees

Land

Initial Fuel Inventory

Operating Spare Parts

Permanent Plant Equipment and Furnishings

Builder's Risk Insurance

Owner Contingency

Other

Total Owner's Cost (2006 US $)

Total Project Cost (2006 US $)

Total EPC Contractor Cost (2006 US $), $/kW (73°F)

Total Project Cost (2006 US $), $/kW (73°F)

550 MW (Net) IGCC

100% PRB

550 MW (Net) IGCC 50%

PRB / 50% Petcoke

$ 86,000,000 $ 86,000,000

$ 22,950,000 $ 22,950,000

$ 28,080,000 $ 28,080,000

$ 46,720,000 $ 47,220,000

$ 47,820,000 $ 50,320,000

$ 2,380,000 $ 2,380,000

$ 1,600,000 $ 1,600,000

$ 36,660,000 $ 44,300,000

$ 102,400,000 $ 102,400,000

$ 354,310,000 $ 306,360,000

$ 149,990,000 $ 158,150,000

$ 20,730,000 $ 20,730,000

$ 94,740,000 $ 96,290,000

$ 42,070,000 $ 42,070,000

$ 23,030,000 $ 23,480,000

$ 24,710,000 $ 24,710,000

$ 8,230,000 $ 8,230,000

$ 4,790,000 $ 4,790,000

$ 40,000,000 $ 40,000,000

$ 57,100,000 $ 55,740,000

$ 119,910,000 $ 117,050,000

$ 4,760,000 $ 4,690,000

$ 1,318,980,000 $ 1,287,540,000

$ 23,000,000 $ 23,000,000

$ 2,910,000 $ 2,910,000

$ 7,500,000 $ 7,500,000

$ 10,930,000 $ 6,190,000

$ 10,060,000 $ 10,120,000

$ 4,600,000 $ 4,600,000

$ 5,940,000 $ 5,790,000

$ 70,200,000 $ 67,950,000

$ 20,100,000 $ 11,440,000

$ 155,240,000 $ 139,500,000

$ 1,474,220,000 $ 1,427,040,000

$ 2,390 $ 2,330

$ 2,670 $ 2,580

7-5

IGCC OPERATIONS AND MAINTENANCE

O&M Assumptions

The following describes the methodology and major assumptions used in the development of the

O&M estimate.

• Fixed costs include such items as plant staffing, office and administration, training, safety, contract staff, annual inspections, standby power energy costs and other miscellaneous fixed costs.

• Variable costs include such items as gas turbine, steam turbine, HRSG, gasifier, and syngas treatment scheduled maintenance, water treatment, wastewater disposal, consumables, landfill costs, balance of plant equipment maintenance and replacements, unplanned maintenance activities, and estimated emissions allowance costs.

• Emissions allowance costs are included in the variable O&M at $3,000/ton of NO x

$1,000/ton of SO

, and $20,000/lb of mercury, based on input from CPS Energy.

• Costs are shown in 2006 US dollars.

• 85% capacity factor (7446 hrs/year at 100% load).

• 2 cold starts per year.

• Additional staff is required above that of a PC unit due to the additional process-related equipment associated with an IGCC project. 126 full time operations and maintenance personnel have been assumed.

• The gas turbine major maintenance costs are based on Long Term Service Agreement

(LTSA) contracts with GE executed for similar equipment.

• Other fixed and variable O&M estimates are based on information obtained by Burns &

McDonnell from plant operators of similar installations.

• Raw water is available at zero cost (other than treatment costs) and wastewater is discharged to a river at zero costs (other than treatment costs)

8-1

IGCC Operations and Maintenance

• Flyash (the amount not recycled to the gasifier) and slag are landfilled on-site at a cost of

$11.29/ton. This cost includes the ongoing cost of closing old landfill cells and expanding the landfill in the future.

• Sulfur produced in the SRU is assumed to be sold at zero cost, thus avoiding any disposal cost.

O&M Exclusions

The costs not included in the O&M estimates include, but are not limited to the following:

• Property taxes.

• Insurance (included in economic analysis).

• Fuel and fuel supply costs (included in economic analysis).

• Initial spare parts (included in capital cost estimate).

O&M Results

The estimated O&M costs for the project are provided in Table 8-1. Additional O&M cost detail can be found in Appendix G.

8-2

IGCC Operations and Maintenance

Table 8-1

IGCC O&M Summary (2006 US Dollars)

100% PRB 50% PRB / 50%

Petcoke

Fixed O&M

Labor, $/yr

Office and Admin, $/yr

Major Inspections, $/yr

Standby Power Energy Costs, $/yr

Other Fixed O&M, $/yr

Fixed O&M, $/yr

Variable O&M (85% CF)

Emissions Allowance Costs, $/yr

NO x

Emissions Allowance Cost

Hg Emissions Allowance Cost

Major Maintenance Costs, $/yr

Steam Turbine / Generator Overhaul

HRSG Major Replacements

Gasifier Replacements

Candle Filter Major Replacements

Gas Turbine Major Replacements

Syngas Treatment Major Replacements

Air Separation Unit Major Replacements

Mercury Carbon Bed Replacements

HCN/COS Hydrolysis Catalyst Replacements

Shift Catalyst Replacements

Demin System Replacements

Water Treatment, $/yr

Fly Ash & Slag Disposal

Other Variable O&M, $/yr

Variable O&M, $/yr (85% CF)

Fixed O&M, $/kW-yr

Variable O&M, $/MWh

Total O&M Cost, $/Year (85% CF)

$ 11,835,700 $ 11,835,700

$ 118,400 $ 118,400

$ 400,000 $ 400,000

$ 98,600 $ 98,600

$ 1,479,500 $ 1,479,500

$ 13,932,200 $ 13,932,200

$ 3,588,300 $ 3,472,900

$ 360,700 $ 429,400

$ 590,000 $ 370,600

$ 260,400 $ 260,400

$ 200,000 $ 200,000

$ 885,800 $ 765,900

$ 300,000 $ 300,000

$ 8,148,700 $ 8,148,700

$ 375,000 $ 395,000

$ 275,000 $ 275,000

$ 530,300 $ 530,300

$ 640,000 $ 640,000

$ - $ -

$ 3,600 $ 3,600

$ 1,479,100 $ 1,523,700

$ 1,560,200 $ 642,100

$ 5,297,400 $ 5,355,600

$ 24,494,500 $ 23,313,200

$ 25.19 $ 25.19

$ 5.95 $ 5.66

$ 38,426,700 $ 37,245,400

8-3

IGCC AVAILABILITY

General

Some IGCC facilities have been evaluated with a spare gasifier to increase availability factors and allow increased operational flexibility. It is anticipated that adding a spare gasifier train will improve the availability factor of the IGCC facility by approximately 5 percentage points. The spare gasifier is typically operated in hot-standby mode which requires natural gas (or syngas if available) to maintain the metal temperatures within the gasification system. This significantly reduces gasifier startup time in the event that one of the gasifiers is forced off-line. The benefits of the spare gasifier, however, come at a large operating and capital expense (approximately 20% capital cost increase). For these reasons, a spare gasifier was not considered for this project.

Assumptions and Clarifications

Plant availability factors are typically determined from historical data of existing plants, which is often a good predictor for the future. Since IGCC technology is relatively new, published availability information is difficult to obtain.

The availability factor is a measure of the amount of the year that the plant or unit is available to operate and produce electricity. It includes the effect of both planned and forced outages.

Past data from existing IGCCs has indicated availability factors of 83-85% for designs that do not utilize a spare gasifier. These existing facilities had first year availabilities of approximately

75%, followed by 80% in the second year, followed by 83-85% in the third year and thereafter.

It is expected that improvements in gasifier designs will improve availability factors from previous generation designs.

Availability Factor

For this assessment, an 85% availability factor is assumed for both IGCC options.

The availability factor of an IGCC facility will depend heavily on the structure of the O&M programs and how well they are executed. The most effective IGCC facilities are those that commit to and follow well organized plans.

As previously noted, the membrane wall design of the Shell gasifier will experience less frequent maintenance than the GE and ConocoPhillips refractory lined gasifiers. Refractory lined

9-1

IGCC Availability

gasifiers will require periodic refractory replacement (perhaps every two years). This results in a lower planned outage rate for the Shell gasifier, and therefore a higher availability factor.

9-2

IGCC EMISSIONS ESTIMATES

General

The emissions evaluated for this IGCC study are NO x

, SO

, PM

, CO, CO

, and mercury. The actual emissions limits and emissions control technology required for a facility are dictated by the air permitting process. The emission rates herein are used to provide the basis of the capital cost, performance, and O&M costs. Actual permitted rates may vary from the emission rates shown below.

capture was not considered for the two base case options; however Chapter 13 provides additional information regarding the impact to the capital cost, performance, and CO

emissions from the addition of CO

capture equipment at a later date.

For purposes of this study, it is assumed the project is located in an attainment area for National

Ambient Air Quality Standards (NAAQS) Pollutants as set by the Environmental Protection

Agency (EPA).

For SO

control, the AGR process selected for the basis of this project is SELEXOL. The AGR is sized to achieve a total sulfur content of 30 ppmv in the syngas to the gas turbines (for the non-

capture cases). High levels of sulfur removal are accomplished by first passing the syngas through a COS hydrolysis reactor prior to the SELEXOL scrubber to convert small amounts of

COS in the syngas to H

NO x

control is achieved through the use of nitrogen injection and syngas saturation into the gas turbine. The nitrogen acts as a diluent (similar to water injection) to control the flame temperature which is a major source of NO x

. Additionally fuel-bound nitrogen is effectively eliminated by the removal of HCN and NH

in the syngas cleanup system.

An SCR was not included at this phase of the project. Some of the ammonia utilized in an SCR will react with SO

in the exhaust gas to form ammonium bisulfate (ABS) that may plug the heat transfer surfaces in the HRSG. If an SCR were to be used, the sulfur level in the syngas would have to be reduced to approximately 15 ppmv to minimize the potential for ABS formation which would increase the cost of the AGR and SRU. Therefore, the capital cost of the project would increase. Also, the net plant output will be reduced due to the reduction in GTG output

(caused by increased exhaust pressure loss) and the additional steam and auxiliary power requirements of the AGR and SRU. The benefit is that NO x

emissions will be reduced from 15 ppmvd @ 15% O

(from the output of the gas turbines) to approximately 3.5 ppmvd @ 15% O

, however particulate emissions will increase. At $3,000/ ton for NO x

emissions allowances costs

(see Table 8-1), the yearly savings provided by the addition of an SCR may make it an attractive

10-1

IGCC Emissions Estimates

option provided that the technical issues can be overcome. At this stage, SCR was not included due to the technical issues stated above; however additional studies regarding the use of an SCR should be performed in the future.

Particulate control for this project is achieved using candle filters and a water wash scrubber to remove the particulate from the syngas. Beyond the syngas particulate control, there is no additional post-combustion particulate control required.

CO is controlled by the gas turbine combustion system. Additional CO removal is not included.

Mercury control is achieved by using activated carbon adsorbent beds to remove mercury from the syngas prior to combustion and is capable of removing 90+% of the entrained mercury.

The resulting emission rates are shown in Table 10-1.

Table 10-1

IGCC Target Emission Rates

100% PRB 50% PRB / 50%

Petcoke

NO x lb/MMBtu (HHV) ppmvd @ 15% O

2 lb/MWh (net)

0.063

0.581

0.062

0.562

lb/MMBtu (HHV) lb/MWh (net)

10 lb/MMBtu (HHV)

1 lb/MWh (net)

CO lb/MMBtu (HHV) ppmvd lb/MWh (net)

0.019

0.173

0.007

0.065

0.037

0.337

0.023

0.210

0.007

0.065

0.036

0.337

lb/MMBtu (HHV) lb/MWh (net)

% Removal lb/TBtu (HHV) lb/MWh (net)

215

1,985

90%

0.778

7.17E-06

213

1,934

90%

0.496

4.50E-06

1) Particulate matter emissions rate is for front half only excluding back half condensables, for the concentration of particulate matter less than 10 microns in diameter

10-2

SUPERCRITICAL PC ESTIMATES

General

In order to compare IGCC to SCPC technology, Burns & McDonnell estimated the capital costs, performance, O&M, and availability factor of a 550 MW (net) SCPC unit with steam conditions of 3500 psig/1050°F/1050°F. For this assessment, only a 100% PRB fired SCPC was evaluated.

Although much more effort was put into developing IGCC cost estimates than the SCPC estimate for this study, Burns & McDonnell believes the accuracy of the SCPC costs to be equal in accuracy, if not greater than those provided for the IGCC estimates. This is largely due to

Burns & McDonnell involvement with other SCPC projects that have been constructed in recent years and the fact that IGCC definitive cost data with vendor input is not available or is considered confidential at this time.

SCPC Capital Cost Assumptions

The majority of the assumptions and exclusions discussed in Chapter 7.0 are applicable to the

SCPC capital cost estimates. Additional assumptions are as follows.

• Wet flue gas desulfurization (FGD) is assumed for SO

control, and SCR for NO x

control, and a baghouse for particulate control.

• The physical size of the wet FGD is increased beyond that required at this stage to accommodate additional future SO

removal as may be required by future environmental regulations. Based on the Fluor EFG+ CO

capture system (discussed in Chapter 13), approximately 98% SO

removal is required in the FGD, which is higher than currently required. The design capability for future SO

removal is integrated into the design of the

FGD system absorber by adding additional height to the absorber tower and by allocating space for installation of additional recirculation pumps and spray headers that could be added in the future should it be necessary to minimize SO

concentrations entering the

capture system. It is estimated that the provision of this additional space within the absorber tower would increase the initial installed cost of the FGD system by about

$5,000,000, which is included in the capital cost estimate.

• Preliminary foundation design is based on the assumption that shallow, mat-type foundations will be sufficient for all minor foundations. Major structures such as the boiler, steam turbine, APC equipment, coal reclaim, and step up transformers are assumed to require piling.

11-1

Supercritical PC Estimates

• The boiler, steam turbine, and air pollution control equipment are located outdoors.

• The design fuel is based on 100% PRB fuel as provided in Table 3-1.

• An on-site landfill is included for disposal of flyash, bottom ash, and scrubber sludge.

The capital cost estimate includes the initial 5-year cell. The ongoing cost of closing current cells and the addition of future cells is covered in the landfill cost ($/ton) used in the O&M estimate.

SCPC Capital Cost Results

The estimated capital costs for the project are provided in Table 11-1. Additional capital cost detail can be found in Appendix E.

11-2

Supercritical PC Estimates

Table 11-1

550 MW (Net) SCPC Capital Cost Estimate Summary (2006 US Dollars)

Procurement

Boiler/AQC

Steam Turbine

Other Mechanical

Electrical

Water & Chemical Treatment

Structural

Construction

Furnish and Erect

Material Handling

Chimney

Boiler/AQC/STG Erection

Civil / Structural Construction

Mechanical Construction

Electrical Construction

EPC Contractor Indirect Costs

Construction Indirects

Construction Management

Pre-operational startup and testing

Other

Project Indirects

Project Management and Engineering

EPC Contingency

EPC Fee

Other

Total EPC Contractor Cost (2006 US $)

Owner Indirect Costs

Owner's Engineer

Permitting and Licensing Fees

Land

Initial Fuel Inventory

Operating Spare Parts

Permanent Plant Equipment and Furnishings

Builder's Risk Insurance

Owner Contingency

Other

Total Owner's Cost (2006 US $)

Total Project Cost (2006 US $)

Total EPC Contractor Cost (2006 US $), $/kW (73°F)

Total Project Cost (2006 US $), $/kW (73°F)

550 MW (Net) SCPC

100% PRB

$ 182,630,000

$ 40,040,000

$ 48,370,000

$ 35,270,000

$ 4,560,000

$ 1,970,000

$ 46,530,000

$ 15,000,000

$ 171,210,000

$ 156,650,000

$ 85,310,000

$ 61,350,000

$ 24,710,000

$ 8,790,000

$ 4,500,000

$ 38,120,000

$ 46,430,000

$ 97,510,000

$ 3,630,000

$ 1,072,580,000

$ 20,000,000

$ 2,910,000

$ 7,500,000

$ 10,690,000

$ 5,750,000

$ 5,780,000

$ 4,830,000

$ 57,250,000

$ 15,050,000

$ 129,760,000

$ 1,202,340,000

$ 1,950

$ 2,190

11-3

Supercritical PC Estimates

SCPC Performance Assumptions

The majority of the assumptions discussed in Chapter 6 are applicable to the SCPC performance estimates. Additional assumptions are as follows.

• Performance is based on the 100% PRB fuel as provided in Table 3-1.

• Steam turbine consists of four turbine sections (HP, IP, and 2 LP) with a two dual down flow exhausts. The design throttle conditions are 3500 psia with 1050°F main steam and hot reheat temperatures.

• Performance is based on a wet cooling tower, wet scrubber, and baghouse.

SCPC Performance Estimate Results

The results of the performance analysis are provided in Table 11-2.

Table 11-2

550 MW (Net) SCPC Performance Summary

100% PRB

Ambient Dry Bulb Temperature, °F

Ambient Wet Bulb Temperature, °F

Elevation, ft.

Coal Heat Input, MMBtu/hr (LHV)

Coal Heat Input, MMBtu/hr (HHV)

Gross Plant Output, MW

Total Plant Auxiliary Load, MW

Net Plant Output, MW

Net Plant Heat Rate, Btu/kWh (LHV)

Net Plant Heat Rate, Btu/kWh (HHV)

Plant Cooling Requirements, MMBtu/hr (Total)

Steam Cycle Cooling Requirement, MMBtu/hr

BOP Auxiliary Cooling Requirement, MMBtu/hr

Total Makeup Water Requirement

GPM

Acre-ft/year (@ 85% CF)

100

4,648

5,037

623.3

65.4

557.8

8,333

9,030

2,490

2,300

190

5,120

7,950

100

4,644

5,033

614.5

64.5

550.0

8,444

9,150

2,490

2,300

190

5,800

7,950

6,430

7,950

100

4,644

5,033

613.2

64.4

548.8

8,462

9,170

2,490

2,300

190

11-4

Supercritical PC Estimates

SCPC O&M Cost Assumptions

The majority of the assumptions discussed in Chapter 8 are applicable to the SCPC O&M estimates. Additional assumptions are as follows:

• 103 full time operations and maintenance personnel.

• Flyash, bottom ash, and scrubber sludge are landfilled on-site at a cost of $11.29/ton.

This cost includes the ongoing cost of closing old landfill cells and expanding the landfill in the future.

• Delivered limestone for wet scrubbing is based on $18/ton.

• Delivered ammonia for SCR use is based on $658/ton for 19% aqueous solution.

SCPC O&M Exclusions

The costs not included in the O&M estimates include, but are not limited to the following:

• Property taxes.

• Insurance (included in economic analysis).

• Fuel and fuel supply costs (included in economic analysis).

• Initial spare parts (included in capital cost estimate).

SCPC O&M Results

The estimated O&M costs for the project are provided in Table 11-3. Additional O&M cost detail can be found in Appendix G.

11-5

Supercritical PC Estimates

Table 11-3

550 MW (Net) SCPC O&M Summary (2006 US Dollars)

100% PRB

Fixed O&M

Labor, $/yr

Office and Admin, $/yr

Major Inspections, $/yr

Standby Power Energy Costs, $/yr

Other Fixed O&M, $/yr

Fixed O&M, $/yr

Variable O&M (85% CF)

Emissions Allowance Costs, $/yr

NO x

Emissions Allowance Cost

Hg Emissions Allowance Cost

Major Maintenance Costs, $/yr

Steam Turbine / Generator Overhaul

Steam Generator Major Replacements

Baghouse Bag Replacement

SCR Catalyst Replacement

Demin System Replacements

Water Treatment, $/yr

Consumables/Disposal, $/yr

Limestone Consumption

SCR Ammonia (Anhydrous)

Scrubber Sludge Disposal

Fly Ash Disposal

Bottom Ash (Sales) / Disposal

Other Chemical Costs

Other Variable O&M, $/yr

Variable O&M, $/yr (85% CF)

Fixed O&M, $/kW-yr

Variable O&M, $/MWh

Total O&M Cost, $/Year (85% CF)

$ 9,687,800

$ 96,900

$ 280,000

$ 98,600

$ 1,211,000

$ 11,374,300

$ 2,810,100

$ 1,127,900

$ 1,734,700

$ 339,200

$ 893,900

$ 253,400

$ 312,000

$ 4,300

$ 1,759,500

$ 524,700

$ 1,041,800

$ 634,700

$ 1,412,600

$ 351,900

$ -

$ 5,634,800

$ 18,835,500

$ 20.68

$ 4.60

$ 30,209,800

SCPC Emission Rates

A wet scrubber is assumed for SO

control, an SCR for NO x

control, and a baghouse for particulate control.

11-6

Supercritical PC Estimates

The use of SCR is a proven technology on PC units. ABS formation is not as much of a concern on a PC unit as for an IGCC unit. In a PC unit, maximum ammonia slip is designed to be less than 2 ppmvd at the end of a specified operating period (2-3 years). This means the average slip over that period is significantly less. Much of the remaining ammonia after the catalyst is absorbed in the flyash. ABS formation will typically occur in the air preheaters if slip exceeds this maximum point. Additionally, the heat transfer surfaces (except for the air heater) are located upstream of the SCR in a PC boiler, thus limiting downstream cold areas where the ABS can collect. The HRSG, however, has HP, IP, and LP heat transfer surface downstream of the

SCR, which can become plugged with the ABS particulate.

Ammonia salt formation is not as much of a concern on a PC unit as for an IGCC unit. In a PC unit much of the remaining ammonia after the catalyst is absorbed in the flyash, thus ammonia salt formation is limited primarily to that formed in the catalyst while in the presence of ammonia. Additionally, the heat transfer surfaces (except for the air heater) are located upstream of the SCR in a PC boiler, thus limiting downstream cold areas where the ammonia salts can collect. An HRSG, however, has HP, IP, and LP heat transfer surface downstream of the SCR, which can become plugged with the ammonia salts.

Approximately 70% mercury removal has been shown with the combination of an SCR, wet scrubber, and baghouse alone. Additional mercury control can be achieved through the use of halogenated carbon injection or activated carbon injection into the flue gas stream. This was not considered for this assessment due to the small amount of test data that is currently available and the potential for contamination of flyash and gypsum.

The estimated emission rates for the SCPC Unit are provided in Table 11-4.

11-7

Supercritical PC Estimates

Table 11-4

500 MW (Net) SCPC Emissions Estimates

100% PRB

NO x lb/MMBtu (HHV) lb/MWh (net)

2 lb/MMBtu (HHV) lb/MWh (net)

10 lb/MMBtu (HHV)

1 lb/MWh (net)

CO lb/MMBtu (HHV) lb/MWh (net)

0.050

0.458

0.060

0.549

0.015

0.137

0.150

1.373

lb/MMBtu (HHV) lb/MWh (net)

% Removal lb/TBtu (HHV) lb/MWh (net)

215

1,967

70%

2.315

2.12E-05

1) Particulate matter emissions rate is for front half only excluding back half condensables, for the concentration of particulate matter less than 10 microns in diameter

Availability Factor

Historic data for SCPC units in the United States is typically from much earlier vintage units

(1970’s). Since the 1980’s, the majority of SCPC units have been installed in Europe and Asia.

Development of high strength materials has helped to minimize the thermal stresses that caused problems in early units. Additionally, the development of Distributed Control Systems (DCS) has helped make a complex starting sequence much easier to control and minimize tube overheating due to lack of fluid. Additionally, newer units use a particle separator placed into the fluid process during startup to minimize solid particle carryover, which causes erosion of the turbine blades. Therefore, many of the early problems experienced with SCPC units have been corrected.

Historically, an availability factor for subcritical PC units in the United States has been 87%.

Newer supercritical units located overseas have maintained availability factor equal to newer subcritical units at approximately 90% or greater. It is estimated that a new SCPC unit will have an availability factor of approximately 90%.

11-8

ECONOMIC ANALYSIS

General

A pro forma economic analysis was prepared for the three solid fuel alternatives: an IGCC unit utilizing 100% PRB coal, an IGCC unit utilizing 50% PRB coal and 50% petcoke, and a SCPC unit firing 100% PRB. A 20-year economic analysis was developed based on the estimated capital costs, performance, fuel costs, and operating costs of each alternative. A 20-year levelized busbar cost in real dollars was determined for each alternative using a revenue requirements analysis of debt service (including principal and interest), fixed O&M, variable

O&M, and fuel. The economic analysis was conducted on a real basis, and therefore, the analysis does not include escalation for fuel or O&M.

The economic analysis assumes a debt term of 30 years. However, the busbar cost presented is a levelized value for the first 20 years of the Project. There is not a significant difference in the levelized busbar cost when comparing 20-year and 30-year project periods

Other EPRI reports and published papers have assumed a 30-year constant dollar busbar analysis based on typical investor owned utility (IOU) financial assumptions. A municipal utility has access to lower cost financing, through both lower interest rates and higher leverage factors.

Additionally, municipal utilities do not have income tax liability, nor an equity financing component, which typically requires a larger rate of return compared to debt financing. As a result, municipal utilities often have a lower cost of capital compared to typical IOU financing.

Burns & McDonnell estimated capital recovery costs based on debt service payments rather than depreciation and interest. The annual capital recovery costs are equal to the cash flow requirements for debt service payments for both principal and interest associated with 100% debt financing of the project capital expenditures.

Assumptions

The following provides the assumptions utilized in the pro forma economic analysis.

•

Capital Cost Estimates: Table 7-1 and Chapter 11

•

Fuel Cost Assumptions:

PRB Coal Cost (Delivered, 2005$) $1.65/MMBtu

12-1

Economic Analysis

Petcoke Cost (Delivered, 2005$)

Fuel Cost Escalation

•

Operating Assumptions:

Heat Rate Performance

Overall Capacity Factor

$1.14/MMBtu

Excluded (real basis)

Table 6-1 and Chapter 11

85%

IGCC Unit

•

Financing Assumptions:

Permanent Financing Term

Capital Structure

Permanent Financing Fees

Minimum Debt Service Coverage Ratio

Debt Service Reserve Fund

•

Economic Assumptions:

O&M Inflation

•

O&M Cost Assumptions:

Fixed O&M Costs

12-2

50% PRB coal, 50% petcoke

3.0%

30 years

Debt – 100%, Equity – 0%

0.50%

1.00%

1.00

50% of annual debt service funded at financial closing

Excluded (real basis)

Table 8-1 and Chapter 11

Variable O&M Costs

Emissions Allowances

Insurance

Property Taxes

Economic Analysis

Table 8-1 and Chapter 11

Included in Variable O&M

0.05% of capital cost

Exempt

Economic Analysis

The economic pro forma analyses were used to determine the levelized busbar cost of power in real dollars for each alternative. Figure 12-1 presents a graph of the resulting levelized busbar power costs in real dollars for the solid fuel-fired alternatives over a 20 year planning period covering 2006 through 2025. Figure 12-1 was developed by preparing a project pro forma model for each of the alternatives under consideration. The levelized busbar cost in real dollars represents the fixed energy cost in 2006 US dollars that would be equivalent to the busbar cost over 20 years. The economic analysis does not include escalation for fuel and O&M costs.

$50.00

$45.00

$40.00

$35.00

$30.00

$25.00

$20.00

$15.00

$10.00

$5.00

$0.00

Supercritical PC

IGCC - 50% PRB / 50% Pet Coke

IGCC - 100% PRB

Figure 12-1

20-Year Levelized Busbar Cost (2006 US Dollars)

Alternative

$39.28

$40.89

$45.03

12-3

Economic Analysis

Figure 12-2 presents a breakout of the components for the 20-year levelized busbar cost in real dollars for the alternatives in 2006 US dollars.

$50.00

$45.00

$40.89

$45.03

$39.28

$40.00

$35.00

$30.00

$25.00

$20.00

$15.00

$10.00

$5.00

$0.00

$15.10

$4.66

$2.91

$16.62

$12.02

$5.71

$3.54

$19.62

$15.21

$6.01

$3.54

$20.27

Fuel Costs

Variable O&M

Fixed O&M

Debt Service

Supercritical PC IGCC - 50% PRB / 50% Pet

Coke

Alternatives

IGCC - 100% PRB

Figure 12-2

Breakout of 20-Year Levelized Busbar Cost (2006 US Dollars)

The SCPC unit is the lowest cost alternative. Since the SCPC unit is less capital intensive than the two IGCC alternatives, the debt service component for the PC unit is considerably lower, as shown in Figure 12-2. Additionally, the SCPC unit has lower operational and maintenance costs, both variable and fixed, compared to the IGCC alternatives, providing a lower overall project cost.

The IGCC alternative utilizing a fuel blend of PRB coal and petcoke has a lower cost than the

IGCC alternative utilizing only PRB coal, and is only slightly higher than the SCPC alternative.

The IGCC alternative using coal and petcoke has a slightly lower capital cost than the IGCC alternative utilizing 100% coal, therefore the debt service requirements for both IGCC alternatives is nearly equivalent. However, the blended fuel option has a significantly lower heat rate and delivered fuel cost, therefore lowering the project busbar cost relative to the IGCC alternative utilizing 100% coal. The ability to use an opportunity fuel, such as petcoke, allows the overall levelized busbar cost of the IGCC technology to be lower compared to strictly using

PRB coal.

12-4

Economic Analysis

Sensitivity Analysis

A sensitivity analysis was preformed for all three alternatives under the following cases:

•

Interest Rate

•

± 0.5 percentage point

•

Coal Fuel Cost

•

± 10%

The ranges shown above not intended to imply the accuracy of the estimates, but the resulting change in busbar cost for the range shown. It is possible that the capital cost, interest rate, fuel cost, capacity factor, and O&M cost may vary by a larger amount than shown above.

The results of the sensitivity analysis are presented in the tornado diagram in Figures 12-3 through 12-5. The sensitivity analysis results are presented in 2006 US dollars. A tornado diagram illustrates the range of results for each sensitivity case and its impact on the levelized busbar cost in real dollars, and ranks the results from greatest impact to least impact.

Capital Cost -/+ 10%

$37.62

$40.94

Fuel Cost -/+ 10%

Interest Rate -/+ 0.5%

Capacity Factor +/- 5%

$37.77

$38.03

$38.35

$40.80

$40.60

$40.31

O&M Cost -/+ 10%

$38.53

$37.6

$38

$38.7

Figure 12-3

Sensitivity Analysis – SCPC Unit – 100% PRB Coal

$40.03

12-5

Economic Analysis

Capital Cost -/+ 10%

Interest Rate -/+ 0.5%

$38.93

$39.42

Fuel Cost -/+ 10%

Capacity Factor +/- 5%

$39.69

$39.79

$42.10

$42.11

O&M Cost -/+ 10%

$39.97

$38.9

$39

$40.2

Figure 12-4

Sensitivity Analysis – IGCC – 50% PRB Coal / 50% Petcoke

Capital Cost -/+ 10%

$43.01

$41.82

$47.06

Interest Rate -/+ 0.5%

$43.51

$46.64

Fuel Cost -/+ 10%

Capacity Factor +/- 5%

$43.51

$43.90

O&M Cost -/+ 10%

$44.08

$43.0

$43

Figure 12-5

Sensitivity Analysis – IGCC – 100% PRB Coal

$44.3

$42.86

$42.45

$46.56

$46.29

$45.99

12-6

Economic Analysis

The sensitivity analysis indicates that capital cost is the most significant factor affecting the economics of the IGCC alternatives and the SCPC unit. Additionally, the interest rate and fuel cost have the next most significant affects. Since the pro forma analyses assume the project alternatives are financed with 100% debt, changes in the capital cost and interest rate have a significant affect on the economics of the project, due to the large portion of debt service. The cost of fuel is the largest ongoing cost to the project; therefore significant changes in the cost of fuel will affect the economics of the project.

Solid fuel generation resources are capital intensive, and have a construction period that is approximately four years in duration. This results in more capital risk due to interest costs, labor availability and costs, and general inflation. The primary tradeoff for these higher capital risks with a solid fuel generation resource is the long-term stability of solid fuel prices which has few competing uses relative to natural gas that is used by almost all economic sectors including residential heating.

12-7

CO

CAPTURE

General

As a part of this study, Burns & McDonnell was tasked with determining the approximate impacts to performance, cost, O&M, emissions, and levelized busbar cost for the 100% PRB

IGCC and 100% PRB SCPC units from adding CO

capture systems. For this assessment, it was assumed that the plants are existing units with cost and operating characteristics as defined in previous chapters. The CO

capture systems are added as a plant retrofit at a later date.

A CO

capture rate of 90% was targeted for both the IGCC and SCPC technologies. For this assessment, it was assumed the CO

would be compressed into a common carrier CO

pipeline.

The pipeline may serve many purposes including:

• Storage in depleted/disused oil and gas fields.

• Enhanced Oil Recovery (EOR) combined with CO

storage.

• Enhanced coal bed methane recovery (ECBM) combined with CO

storage.

• Storage in deep saline aquifers/formations (DSF) – both open and closed structures.

The assumed common carrier pipeline pressure is 2,000 psig. The cost of the CO

pipeline and/or storage is not included in the estimates.

Table 13-1 provides the assumed CO

purity required for the common carrier pipeline.

13-1

CO2 Capture

Table 13-1

Purity Specification

SUBSTANCE

Hydrocarbons

Glycol

Temperature

Pressure

LIMIT

95%

-40 °C (-40 °F)

100 ppm

25 ppm

0.1%

174 lit/10

6 m

(0.3 gal/MMcf)

50 °C (120 °F) d

13,800 kPa

(2,000 psig)

MAX OR

MIN

Min

Max

Normal

REASON

MMP concern a

MMP concern

Corrosion

Safety

Operations

Materials

Materials a

Minimum miscible pressure concern because the application of the CO

is potentially for EOR. b

Dew point: < -40 °F c

Based on limiting H

S partial pressure to 0.3 kPa, above which the pipeline will be classified for sour service. d

There will also be a lower limit associated with potential failure of the pipeline but this is not relevant to most of the North American pipelines because of their location.

The potential for CO

sales exists, which could help offset the costs associated with CO

capture.

In 2005 EPRI evaluated the potential CO

sales costs for the CO

storage options listed above

(Building the Cost Curve for CO

Storage: North American Sector, EPRI, Palo Alto, CA: 2005.

Report No. 1010167). As a part of this 2005 study, cost curves for each storage option were developed by compiling data on geological reservoirs for CO

storage and determining the technical storage capacity of these reservoirs. These data, along with baseline study data on CO

2 sources, were then analyzed within a purpose-built techno-economic model based upon geographic information system (GIS) technology. The mapping capability of the GIS allowed the presentation of the data base information at both regional and continental scales. The computational portion of the model calculated the distance between each source and accessible candidate storage reservoir and compared characteristics such as CO

flow rate, remaining storage capacity, depth, and other injection parameters, to estimate the cost for CO

transmission and storage for each source and reservoir pair. The overall costs for CO

storage in the USA were modeled to be effectively capped at about $12-15/Mt CO

, with important yet limited resource available below $0/Mt CO

The results of the previous EPRI study are summarized in Figure 13-1.

13-2

CO2 Capture

Figure 13-1

Storage Supply Curve for North America

For purposes of this study, any revenue or cost associated with CO

disposal were not considered. It is assumed that the captured CO

is disposed at zero cost.

If a dedicated pipeline for EOR or other designated purpose were to be used rather than the common carrier pipeline assumed for this report, the design of the CO

capture systems could be significantly different which may produce different results.

There are many legal and regulatory aspects with regard to CO

storage that have not been evaluated for this study.

The capital cost, O&M, and performance assumptions provided in previous sections are applicable for the CO

capture cases.

IGCC CO

Capture

capture in an IGCC facility is accomplished by removing the CO

and water from the syngas prior to combustion. This is achieved by first shifting the syngas to convert CO to CO

and H

by the addition of water-gas shift reactors. The CO

is then absorbed in the AGR unit, resulting in a hydrogen rich fuel. For the purposes of this analysis, SELEXOL was used as the solvent for CO

2 removal (SELEXOL is discussed in greater detail in Chapter 4).

capture for an IGCC facility has not been proven commercially, however CO

capture has been proven commercially at the Dakota Gasification Company’s Great Plains Synfuels Plant, which sends compressed CO

through a pipeline for Enhanced Oil Recovery (EOR).

13-3

CO2 Capture

IGCC Modifications for CO

Capture

For this study, all major modifications for CO

capture are downstream of the gasification block.

These modifications include:

• Replacement of the COS/HCN hydrolysis reactor with two stages of sour shift reaction to convert carbon monoxide to CO

• Additions to the syngas cooling train to incorporate the shift reactors.

• Additions to the SELEXOL AGR to recover CO

as a separate byproduct.

• Addition of a single CO

compressor, consisting of four multi-stage centrifugal compressor cases with intercoolers and CO

product cooler, is included to deliver CO

at 2,000 psig to the pipeline. Heat recovery from CO

compression is not included at this stage, but should be evaluated in the future.

The acid gas composition from the SELEXOL unit to the Sulfur Recovery Units was set at 25%

S as in the non-capture case. The SRU/TGTU design is therefore identical to the non-capture case.

Process flow diagrams for the modified syngas flow train are included in Appendix A. Original equipment that is reused is highlighted in yellow.

Sour Shift

The COS/HCN reactor included in the non-capture case is replaced with two stages of sour shift reaction. The shift reaction converts approximately 95% of the carbon monoxide to CO

2, generating hydrogen fuel as a byproduct. The shift reaction is

CO + H

O Æ H

+ CO

The reactors operate with 1.3 moles of steam feed per mole of dry gas (or 2.1 mole of H

O per mole of CO). IP steam is added upstream of the reactors to replace steam consumed in the reaction. The balance is generated by heating and vaporizing process water.

Cobalt-molybdenum sour shift catalyst is a good COS/HCN hydrolysis catalyst. Both COS and

HCN are almost entirely hydrolyzed in the reactors, eliminating the need for a separate reactor.

Since each mole of CO is replaced with a mole of H

, the available syngas chemical energy

(MMBtu/hr) on an HHV basis actually increases slightly from the un-shifted syngas due to H

2 having a higher HHV heating value than CO. However, since CO does not form water as a byproduct of combustion, the LHV and HHV heating value of CO are identical. Therefore, the

LHV energy of the shifted syngas (MMBtu/hr) decreases by approximately 9.7%.

13-4

CO2 Capture

Syngas Cooling and Condensation

The exothermic shift reaction and the addition of steam to facilitate the reaction significantly increase the heat load on the syngas cooling train. Several new heat exchangers are required to remove this heat. The additional heat is used to preheat the shift feed and to generate part of the steam feed to the reactors.

Due to the number of heat exchangers and additional pressure drop through the AGR, some increase in the gasifier pressure is required to maintain the needed pressure at the inlet of the gas turbines. This increase can be minimized by appropriate design of the exchangers and is believed to be within the design allowance of the gasifier.

Acid Gas Removal (AGR)

The number of moles, and therefore the volumetric flow rate, of syngas feeding the AGR is about 60% higher than in the non-capture case. Although most of the original non-capture equipment (towers, large heat exchangers and refrigeration equipment) can be reused, significant additions are required to handle the additional volumetric flow and to separate CO

as a separate byproduct.

The following new equipment is required:

• H

S absorber (in parallel to original absorber).

• H

S stripper with reboiler, condenser, reflux drum, and pumps (in parallel to original stripper).

• H

S concentrator (common to both H

S absorber/stripper trains).

• Rich solvent pumps to feed H

S absorber bottoms to the H

S concentrator.

• New rich flash compressor and coolers to replace original units.

• CO

absorber.

• Loaded solvent pumps to feed H

S absorbers.

• Solvent regeneration flash drum system (4 drums with CO

recycle compressor and CO

2 vacuum compressor.

• Semi-lean solvent pumps and chiller to feed cold regenerated solvent to CO

absorber.

• Refrigeration package.

IGCC Impacts from CO

Capture

IGCC Performance – CO

Capture

The shift reaction results in a high hydrogen content fuel with a higher heating value (Btu/lb) than for the standard syngas cases. This results in less mass flow through the gas turbines and

13-5

CO2 Capture

less gas turbine power as a result. Additionally, more steam is required for the AGR and a large quantity of IP steam (450,000 lb/hr) is required for the water-gas shift reaction resulting in substantially less steam turbine output.

The auxiliary load of the facility also increases substantially due to the CO

compression

(approximately 37.1 MW) and the increased auxiliary loads of the AGR. The net result is approximately a 25% reduction in net plant output and a 39% increase in net plant heat rate.

The cooling load of the facility decreases since a large portion of the steam is extracted for the

AGR and water-gas shift reaction. However due to the large amount of steam leaving the cycle, the plant makeup requirement has increased by approximately 23%.

Table 13-2 illustrates the impact of CO

capture on the IGCC facility.

Table 13-2

IGCC Performance Impacts from CO

Capture

Ambient Dry Bulb Temperature, °F

Ambient Wet Bulb Temperature, °F

Elevation, ft.

Evaporative Cooling, On/Off

Coal Heat Input, MMBtu/hr (LHV)

Coal Heat Input, MMBtu/hr (HHV)

Gas Turbine Gross Output, MW (each)

Gas Turbine Gross Output, MW (total)

Steam Turbine Gross Output, MW

Gross Plant Output, MW

Auxiliary Load

Power Block, MW

Material Handling, MW

Air Separation Unit, MW

Gasifier, MW

Compression

Syngas Treatment, MW

Total Plant Auxiliary Load, MW

Net Plant Output, MW

Net Plant Heat Rate, Btu/kWh (LHV)

Net Plant Heat Rate, Btu/kWh (HHV)

Plant Cooling Requirements, MMBtu/hr (Total)

Steam Cycle Cooling Requirement, MMBtu/hr

BOP Auxiliary Cooling Requirement, MMBtu/hr

Total Makeup Water Requirement

GPM

Acre-ft/year (@ 85% CF)

553.0

8,510

9,220

2,141

1,480

661

22.0

5.9

122.1

2.1

0.0

4.7

156.8

Base Case

(100% PRB)

100

Off

4,705

5,099

224.9

449.7

260.1

709.9

Capture

(100% PRB)

100

Off

4,883

5,291

213.8

427.5

202.6

630.1

4,980

6,830

6,147

8,430

413.3

11,810

12,800

2,101

1,120

981

22.0

6.2

123.4

2.2

37.1

26.0

216.8

13-6

CO2 Capture

IGCC Capital Cost – CO

Capture

In addition to the revised AGR costs, syngas treatment costs, and CO

compression costs, the demineralized water treatment and storage system must be upgraded due to the 450,000 lb/hr of

IP steam being used for the water-gas shift reaction.

For the CO

capture case, much more heat load (approximately 300 MMBtu) is transferred to the condensate (See heat exchanger SGT-HTX-110 in Appendix A). This results in significantly more LP steam production than in the Base Case. The LP superheater provided in the Base Case

HRSG is undersized to superheat this amount of steam. Therefore, $2,000,000 in HRSG modifications are required to increase the size of the HRSG LP superheaters.

The additional capital cost estimated for CO

capture retrofit is shown in Table 13-3. The capital cost is provided in overnight mid-2006 US dollars.

Table 13-3

IGCC Capital Cost Additions for CO

Capture Retrofit

Installed Costs

AGR and Syngas Treatment Modifications

Compressors

Additional Demineralized Water Treatment & Storage

HRSG LP Superheater Modifications

Total EPC Retrofit Cost (2006 US $)

Owner's Costs

Total Retrofit Cost (2006 US $)

$ 156,620,000

$ 16,600,000

$ 4,000,000

$ 2,000,000

$ 179,220,000

$ 17,960,000

$ 197,180,000

Total EPC Plant Costs (Including Base Case)

Total Project Costs (Including Base Case)

$ 1,498,200,000

$ 1,671,400,000

Total EPC Contractor Cost (2006 US $), $/kW (73°F)

Total Project Cost (2006 US $), $/kW (73°F)

$ 3,630

$ 4,040

The cost of the CO

pipeline and/or storage is not included in the estimates.

IGCC Operations and Maintenance – CO

Capture

Due to the increased size and role of the AGR for the CO

capture case, it is assumed that an additional control room operator is required for each shift, resulting in a plant staff of 130.

Other impacts to O&M are minimal from a $/year perspective, however due to the reduced output of the facility, the O&M increases greatly on a $/kW-yr and $/MWh basis.

The CO

that is captured is assumed to be sold to the common carrier pipeline at zero cost.

13-7

CO2 Capture

The O&M for the IGCC facility with and without CO

capture is provided in Table 13-4.

Table 13-4

IGCC O&M Impacts from CO

Capture

Base Case

(100% PRB)

Capture

(100% PRB)

Fixed O&M

Labor, $/yr

Office and Admin, $/yr

Major Inspections, $/yr

Standby Power Energy Costs, $/yr

Other Fixed O&M, $/yr

Fixed O&M, $/yr

Variable O&M (85% CF)

Emissions Allowance Costs, $/yr

NO x

Emissions Allowance Cost

Hg Emissions Allowance Cost

Major Maintenance Costs, $/yr

Steam Turbine / Generator Overhaul

HRSG Major Replacements

Gasifier Replacements

Candle Filter Major Replacements

Gas Turbine Major Replacements

Syngas Treatment Major Replacements

Air Separation Unit Major Replacements

Mercury Carbon Bed Replacements

HCN/COS Hydrolysis Catalyst Replacements

Shift Catalyst Replacements

Demin System Replacements

Water Treatment, $/yr

Fly Ash & Slag Disposal

Other Variable O&M, $/yr

Variable O&M, $/yr (85% CF)

Fixed O&M, $/kW-yr

Variable O&M, $/MWh

Total O&M Cost, $/Year (85% CF)

$ 11,835,700 $ 12,209,200

$ 118,400 $ 122,100

$ 400,000 $ 400,000

$ 98,600 $ 98,600

$ 1,479,500 $ 1,526,200

$ 13,932,200 $ 14,356,100

$ 3,588,300 $ 3,604,800

$ 360,700 $ 78,800

$ 590,000 $ 612,000

$ 260,400 $ 260,400

$ 200,000 $ 200,000

$ 885,800 $ 885,800

$ 300,000 $ 300,000

$ 8,148,700 $ 8,148,700

$ 375,000 $ 587,500

$ 275,000 $ 275,000

$ 530,300 $ 530,300

$ 640,000 $ -

$ - $ 1,020,000

$ 3,600 $ 20,100

$ 1,479,100 $ 2,066,800

$ 1,560,200 $ 1,560,200

$ 5,297,400 $ 6,154,900

$ 24,494,500 $ 26,305,300

$ 25.19 $ 34.74

$ 5.95 $ 8.55

$ 38,426,700 $ 40,661,400

13-8

CO2 Capture

IGCC Emissions – CO

Capture

emissions are reduced by 90% in the SELEXOL unit. In order to meet the CO provided in Table 13-1, 25 ppm H

S is required at the outlet of the H

purity spec

S absorber. From the H

S absorber, the low H

S content syngas is then passed through a CO

2 absorber where the CO

is stripped off. Because the low H

S content syngas is again exposed to the SELEXOL solvent in the CO2 stripper, the sulfur content of the syngas is reduced significantly (approximately 1 ppm

COS and 1 ppm H

S), resulting in a reduction of SO

emissions (ton/yr) by approximately 80%.

The resulting emission rates are shown in Table 13-5.

Table 13-5

IGCC Emissions Impacts from CO

Capture

Base Case

(100% PRB)

Capture

(100% PRB)

NO x lb/MMBtu (HHV) ppmvd @ 15% O

2 lb/MWh (net)

2 lb/MMBtu (HHV) lb/MWh (net)

10 lb/MMBtu (HHV)

1 lb/MWh (net)

CO lb/MMBtu (HHV) ppmvd lb/MWh (net)

2 lb/MMBtu (HHV) lb/MWh (net)

% Removal lb/TBtu (HHV) lb/MWh (net)

0.063

0.581

0.019

0.173

0.007

0.065

0.037

0.337

215

1,985

90%

0.778

7.17E-06

0.061

0.781

0.004

0.051

0.007

0.090

0.035 (Note 2)

25 (Note 2)

0.448 (Note 2)

276

90%

0.778

9.96E-06

1) Particulate matter emissions rate is for front half only excluding back half condensables, for the concentration of particulate matter less than 10 microns in diameter

2) GE is currently in the process of developing tools to accurately predict CO emissions for high hydrogen fuels. It is estimated that CO emissions will be less than shown for IGCC technology, however to what extent is unknown at this time.

13-9

CO2 Capture

IGCC Pre-Investment Options for CO

Capture

This study was performed with minimal pre-investment for CO

capture equipment other than allowing space for future expansion and including SELEXOL in the base case (which may be the

AGR of choice without consideration for CO

capture as discussed in Chapter 4). Other options for pre-investment include:

• Design syngas cooler with a hotter exit temperature, resulting in more water being vaporized in the syngas scrubber and decreasing steam demand upstream of the water-gas shift. This results in lower cost of the syngas cooler and better CO

capture performance, however it also results in higher heat rate during non-capture operation.

• Supplemental duct firing can be added to the HRSG to make up for loss of steam turbine output.

• Increase size of initial gasification block to allow for additional syngas production to increase output for CO

capture cases (in particular the cold ambient conditions which are limited on syngas).

SCPC CO

Capture

Unlike IGCC technology, SCPC technology utilizes post-combustion capture of CO

using chemical absorption, also capable of achieving 90% removal efficiencies. Different technologies are available that use various solvents. Mitsubishi Heavy Industries (MHI) utilizes a tertiary amine solvent called KS-1; additionally ammonia-based technology is being developed that utilizes aqueous ammonium carbonate to capture CO

as ammonium bicarbonate.

The technology evaluated for this study is based on Fluor’s Econamine FG Plus

(EFG+) CO

2 capture technology, which is based on a formulation of monoethanolamine (MEA) and proprietary additives for operation in high O

content gas and for corrosion resistance. A block flow diagram provided by Fluor is provided in Figure 13-2.

13-10

CO2 Capture

Figure 13-2

Fluor EFG+ Block Flow Diagram

The purpose of the EFG+ plant is to recover 90% of the carbon dioxide from the flue gas of the existing the FGD. The plant consists of an Absorption section and a Stripper section. This results in a plant with a total capacity of 11,697 ton/day (100% CO

basis).

The EFG+ plant battery limit for the flue gas feed is at the exit of the FGD. All of the flue gas from the FGD is routed to the EFG+ plant thus resulting in a zero flow of gas through the existing stacks to the atmosphere. The flue gas enters the Flue Gas Conditioning Unit (FGCU) where the gas is cooled by a circulating water stream, and the sulfur content of the gas is lowered from 7 ppmv to 1 ppmv. By lowering the gas temperature, much of the water vapor contained in the flue gas is condensed and separated from the feed gas before entering the Absorber.

The cooled, overhead gas from the FGCU is routed by a Blower to the Absorber. The flue gas enters the bottom of the Absorber and flows upwards counter current to the circulating solvent.

The solvent reacts chemically to remove the carbon dioxide in the feed gas. Residue gas, consisting mainly of nitrogen and oxygen, is vented through the top of the Absorber.

13-11

CO2 Capture

The rich solvent, containing absorbed carbon dioxide from the Absorber, is routed to the

Stripper. The rich solvent enters the Stripper and flows down counter current to stripping stream, which removes carbon dioxide from the rich solvent. Heat for stripping is supplied by low pressure steam via the Reboiler. Lean solvent from the Stripper is routed back to the

Absorber. The overhead vapor from the Stripper is routed to the Product CO

Compressor.

To maintain the highest possible absorption capacity of the solvent, contaminants, such as heat stable salts, are continuously removed in the Reclaimer.

EFG+ technology has not been proven commercially for a full scale PC unit, however commercial experience exists for capturing CO

from natural gas and fuel oil fired units, primarily for use in the food industry, EOR, and urea plants. Two demo plants have been constructed in Japan firing LPG and an oil/coal mixture. Additionally, Fluor is currently developing two demonstration plants that will fire coal and natural gas.

SCPC Modifications for CO

Capture

The Econamine FG Plus (EFG+) process for CO

capture requires that the level of SO

in the flue gas be minimized. Any SO

entering the EFG+ CO

absorber will react with the MEA solvent resulting in formation of waste salts that must be purged from the system. Therefore, approximately 7 ppm (approximately 98% removal with PRB fuel) SO

is required at the inlet to

Fluor’s flue gas conditioning system. To the extent that the SO

entering the EFG+ process is greater than about 1 ppm, it must be reduced to that level within the EFG+ process upstream of the CO

absorber. The EFG+ process accomplishes this reduction by scrubbing the flue gas with sodium hydroxide (NaOH).

In order to provide 7 ppm inlet SO

to the EFG+ process as described above, additional FGD SO

2 removal capacity must be installed in the wet FGD. Since the FGD system was initially designed with a space allocation for future SO

/CO

control, new internal spray headers and the recycle pumps can be installed at this time to reduce the overall inlet SO

to the 7 ppm required.

The installed cost for the FGD internals and recycle pumps is approximately $2.5 million.

Because this analysis is performed from a retrofit standpoint, the following modifications to the existing SCPC unit are required. All major modifications for CO

capture are downstream of the existing wet FGD. These include:

• Addition of wet FGD upgrades described above.

• Addition of Fluor EFG+ System.

• Addition of a single CO

compressor, consisting of four multi-stage centrifugal compressor cases with intercoolers and product cooler, is included to deliver CO

at 2,000 psig to the pipeline. Heat recovery from CO

compression is not included at this stage, but should be evaluated in the future.

• Although the steam turbine condenser duty is less than before, the EFG+ system requires approximately 1,730 MMBtu/hr of auxiliary cooling, resulting in the need for additional cooling capacity. This is accomplished by the addition of a new cooling tower and circulating water system.

13-12

CO2 Capture

SCPC Impacts from CO

Capture

SCPC Performance – CO

Capture

The SCPC performance adjustments for CO

capture are as follows:

• Approximately 1.4 million lb/hr of saturated LP steam (45 psig) is required by the EFG+

Reboiler. Steam is taken from the IP steam turbine exhaust to supply this steam. This extraction is approximately 40% of the flow from the IP turbine exhaust, which reduces the steam turbine output by approximately 93 MW. The remaining steam through the steam turbine is sufficient for providing adequate blade cooling.

• Additionally, the EFG+ system has an auxiliary load of approximately 19 MW.

• The additional cooling capacity auxiliary load discussed above is estimated at 3.5 MW.

• Approximately 42.6 MW of CO

compression is required to compress the CO

to 2,000 psig.

• Approximately 2 MW for addition of new FGD recycle pumps.

The net result is approximately a 29% reduction in net plant output and a 41% increase in net plant heat rate.

Due to the large auxiliary cooling requirement of the EFG+ system, the plant makeup water requirement increased by approximately 34%.

The resulting performance is show in Table 13-6, both pre and post-CO

capture.

13-13

CO2 Capture

Table 13-6

SCPC Performance Impacts from CO

Capture

Ambient Dry Bulb Temperature, °F

Ambient Wet Bulb Temperature, °F

Elevation, ft.

Coal Heat Input, MMBtu/hr (LHV)

Coal Heat Input, MMBtu/hr (HHV)

Gross Plant Output, MW

Total Plant Auxiliary Load, MW

Net Plant Output, MW

Net Plant Heat Rate, Btu/kWh (LHV)

Net Plant Heat Rate, Btu/kWh (HHV)

Plant Cooling Requirements, MMBtu/hr (Total)

Steam Cycle Cooling Requirement, MMBtu/hr

BOP Auxiliary Cooling Requirement, MMBtu/hr

Total Makeup Water Requirement

GPM

Acre-ft/year (@ 85% CF)

Base Case

(100% PRB)

100

Capture

(100% PRB)

100

4,644

5,033

614.5

64.5

550.0

8,440

9,150

2,490

2,300

190

4,644

5,033

521.4

131.6

389.8

11,910

12,910

3,330

1,354

1,976

5,800

7,950

7,757

10,640

SCPC Capital Cost – CO

Capture

The additional capital cost encountered once CO

capture equipment is installed is shown in

Table 13-7. The capital cost is provided in overnight mid-2006 US dollars.

13-14

CO2 Capture

Table 13-7

SCPC Capital Cost Additions for CO

Capture Retrofit

Installed Costs

Fluor Econamine FG+ System

Compressors

FGD Modifications to Obtain 98% SO

Removal

Additional Cooling Capacity

Total EPC Retrofit Cost (2006 US $)

Owner's Costs

Total Retrofit Cost (2006 US $)

Total EPC Plant Costs (Including Base Case)

Total Project Costs (Including Base Case)

Total EPC Contractor Cost (2006 US $), $/kW (73°F)

Total Project Cost (2006 US $), $/kW (73°F)

The cost of the CO

pipeline is not included in the estimates.

$ 243,000,000

$ 17,530,000

$ 2,500,000

$ 6,400,000

$ 269,430,000

$ 26,570,000

$ 296,000,000

$ 1,342,010,000

$ 1,498,340,000

$ 3,440

$ 3,840

SCPC Operations and Maintenance – CO

Capture

Based on input from Fluor, an additional control room operator and field operator are required

(per shift), resulting in a plant staff of 111.

Other impacts to O&M are minimal from a $/year perspective, however due to the reduced output of the facility, the O&M increases greatly on a $/kW-yr and $/MWh basis.

The CO

that is captured is assumed to be sold to the common carrier pipeline at zero cost.

The O&M for the SCPC facility with and without CO

capture is provided in Table 13-8.

13-15

CO2 Capture

Table 13-8

SCPC O&M Impacts from CO

Capture

Fixed O&M

Labor, $/yr

Office and Admin, $/yr

Major Inspections, $/yr

Standby Power Energy Costs, $/yr

Other Fixed O&M, $/yr

Fixed O&M, $/yr

Variable O&M (85% CF)

Emissions Allowance Costs, $/yr

NO x

Emissions Allowance Cost

Hg Emissions Allowance Cost

Major Maintenance Costs, $/yr

Steam Turbine / Generator Overhaul

Steam Generator Major Replacements

Baghouse Bag Replacement

SCR Catalyst Replacement

Demin System Replacements

Water Treatment, $/yr

Consumables/Disposal, $/yr

Limestone Consumption

SCR Ammonia (Anhydrous)

Scrubber Sludge Disposal

Fly Ash Disposal

Bottom Ash (Sales) / Disposal

Other Chemical Costs

Other Variable O&M, $/yr

Variable O&M, $/yr (85% CF)

Fixed O&M, $/kW-yr

Variable O&M, $/MWh

Total O&M Cost, $/Year (85% CF)

Base Case

(100% PRB)

Capture

(100% PRB)

$ 9,687,800 $ 10,434,900

$ 96,900 $ 104,300

$ 280,000 $ 280,000

$ 98,600 $ 98,600

$ 1,211,000 $ 1,304,400

$ 11,374,300 $ 12,222,200

$ 2,810,100 $ 2,529,400

$ 1,127,900 $ 4,800

$ 1,734,700 $ 1,734,900

$ 339,200 $ 339,200

$ 893,900 $ 893,900

$ 253,400 $ 253,400

$ 312,000 $ 312,000

$ 4,300 $ 4,300

$ 1,759,500 $ 2,372,900

$ 524,700 $ 551,200

$ 1,041,800 $ 1,042,000

$ 634,700 $ 666,800

$ 1,412,600 $ 1,412,800

$ 351,900 $ 351,900

$ - $ 2,236,500

$ 5,634,800 $ 5,634,800

$ 18,835,500 $ 20,340,800

$ 20.68 $ 31.19

$ 4.60 $ 6.97

$ 30,209,800 $ 32,563,000

13-16

CO2 Capture

SCPC Emissions – CO

Capture

In addition to removing 90% of CO

emissions, the outlet SO

from the EFG+ Absorber is reduced to approximately 0.1 ppm (99.9+% removal) and NO x

emissions are reduced by approximately 10%. The resulting emission rates are shown in Table 13-9. Additionally, these reduced emissions are reflected in the O&M costs provided in Table 13-8.

Table 13-9

SCPC Emissions Impacts from CO

Capture

Base Case

(100% PRB)

Capture

(100% PRB)

NO x lb/MMBtu (HHV) lb/MWh (net)

2 lb/MMBtu (HHV) lb/MWh (net)

10 lb/MMBtu (HHV)

1 lb/MWh (net)

CO lb/MMBtu (HHV) lb/MWh (net)

2 lb/MMBtu (HHV) lb/MWh (net)

% Removal lb/TBtu (HHV) lb/MWh (net)

0.050

0.458

0.060

0.549

0.015

0.137

0.150

1.373

215

1,967

70%

2.315

2.12E-05

0.045

0.581

0.0003

0.003

0.015

0.194

0.150

1.937

278

70%

2.315

2.99E-05

1) Particulate matter emissions rate is for front half only excluding back half condensables, for the concentration of particulate matter less than

10 microns in diameter

SCPC Pre-Investment Options for CO

Capture

This study was performed with minimal pre-investment in CO

capture equipment. The only pre-investments made were the increase in FGD absorber size, allowing expansion of the FGD to achieve 7 ppm SO

in the future for the CO

capture case and the plot space allocation for future

capture equipment. Other options for pre-investment that should be further evaluated in the future are as follows:

13-17

CO2 Capture

• The use of a deaerating condenser in lieu of a standard deaerator arrangement (open feedwater heater) allows for boiler feedwater to be routed to the CO

compressor interstages, providing reduced compressor auxiliary load and less steam extraction from the steam cycle.

• Increasing the size of the wet FGD to reduce SO

emissions to 1 ppm (instead of 7 ppm assumed for this evaluation). This would eliminate the need for the sodium hydroxide scrubber currently included in Fluor’s scope. Although achieving this low of an SO

2 emission with a wet FGD is typically cost prohibitive, it is likely more cost effective that the use of the sodium hydroxide scrubber. It should be noted that obtaining SO

2 guarantees of 1 ppm from FGD vendors is not likely at this stage.

• Other multi-pollutant flue gas clean-up systems such as J-Power’s ReACT

system

(utilizing regenerated activated carbon) and Powerspan’s ECO

system (utilizing electrocatalytic oxidation) may provide emissions requirements more acceptable for SCPC CO

2 capture technology without the need for major modifications.

CO

Capture Economics

A 20-year levelized busbar cost analysis was performed using the same assumptions as provided in Chapter 12. The resulting busbar costs are provided in Table 13-10.

Table 13-10

CO2 Capture Busbar Costs

Base Case

(100% PRB)

Capture

(100% PRB)

% Increase

IGCC 20-year levelized busbar cost (2006 Real $)

SCPC 20-year levelized busbar cost (2006 Real $)

$45.03

$39.28

$65.41

$62.00

45%

58%

The avoided CO

cost can be determined by dividing the differential busbar cost between the capture and non-capture cases by the differential metric tons/MWh between the capture and noncapture cases.

The resulting avoided CO

costs are as follows:

• IGCC

$26.28 / Mt CO

avoided

• SCPC

$29.64 / Mt CO

avoided

The results indicate that adding CO

capture to an existing IGCC is a more efficient means of reducing CO

emissions than adding CO

capture equipment to an existing SCPC facility; however the initial busbar cost difference (pre-CO

capture) between the two technologies still results in PC technology having the lowest post-capture busbar cost.

13-18

CO2 Capture

A brief analysis was performed to determine what CO

emissions allowance cost ($/Mt) would be required to justify the expense of the addition of CO

capture to both technologies (assuming

is sold at zero cost). Approximately $30/Mt for SCPC technology and $26/Mt for IGCC technology were determined to be the break-even points. An allowance cost above these figures may justify the additional expense of installing CO

capture equipment. Additionally, any CO

2 sales above zero cost ($/Mt) would reduce the breakeven point accordingly.

13-19

OTHER CONSIDERATIONS

Byproduct Sales

The two major byproducts from the IGCC process are slag and sulfur. The slag coming off of the bottom of the gasifier is vitrified, has low bulk density, high shear strength, and good leachability characteristics. As such, IGCC slag has the ability to be utilized as a feedstock to a number of different industries.

Identified markets for IGCC slag include:

• Construction structural backfill

• Asphalt paving aggregate

• Portland cement aggregate

• Asphalt shingle roofing granules

• Pipe bedding material

• Blasting grit

• Mineral filler

• Road drainage media

• Water filtering medium

• Water-jet cutting

The sulfur in the syngas is removed in the AGR and then generally either sent to a Claus unit to convert it to elemental sulfur or to a sulfuric acid plant for to make sulfuric acid. The sulfur or sulfuric acid is also utilized in a number of industries, including asphalt, and agriculture.

A smaller potential by-product is the flyash. The flyash produced by the Shell gasifier has very low carbon content and therefore has attractive qualities for use in cement manufacturing.

Co-Production

One advantage of the IGCC technology is the capability of producing a variety of chemicals in addition to the production of electricity, especially during the times of the year when it may not be economically attractive to produce power.

The properties of the syngas produced by the coal gasification process can be adjusted to allow a range of hydrogen to carbon monoxide molar rations, and stand alone gasification plants have been operating for years with refinery waste streams to produce syngas for chemical production.

Various options for downstream integration correspond to a range of value added products.

Figure 14-1 identifies some of the possible products resulting from coal gasification.

14-1

Other Considerations

Power

Generation

Coal

Gasification

Synthesis Gas

Methanol

- Acetate products

- Acetic Acid

- Ethylene / Propylene

Figure 14-1

Products from Syngas

Fisher-Tropes

Liquids

- Gasoline

- Diesel

- Jet Fuel

Hydrogen

-Ammonia

-Fertilizers

- Urea

Synthetic

Natural Gas

- Enhanced oil recovery

Plant Degradation

Plant degradation has not been included in the performance estimates or economic analysis. It should be noted that gas turbine degradation (and consequently steam turbine performance reduction) can be significant over time. This may result in 4-5% average degradation over the life of the plant depending on frequency of water wash and gas turbine maintenance (compared to ~2% for a PC Unit).

Lignite Gasification

Another potential lower cost feedstock for an IGCC in Texas would be lignite. While lignite is an abundant resource in Texas, the combination of its high ash content and high moisture content, makes it unattractive to be transported to power plants. Instead, lignite-based power plants are typically located at the “mine mouth”. In the present study, the site location is not near a lignite resource and therefore lignite was not evaluated as a fuel.

However, if a mine-mouth site was used, it might be an economic option. Mine-mouth lignite’s lower fuel cost must be balanced against some undesirable impacts on the IGCC design.

Compared to PRB coal, Texas lignite has more ash, more sulfur, and more moisture. Each of these has a negative impact on thermal efficiency while increasing the capital cost of the design.

Since the Shell gasification technology, a dry coal-feed gasifier, is used here, lignite may be used and still produce plant efficiency in the upper 30’s. The off-set is the increase in coal drying energy required. The use of coal drying processes that utilize low level energy, such as the RWE

Vapour Compression cycle, may make use of the abundant low-level energy in the IGCC cycle that is currently going unused. The use of lignite in slurry-feed gasifiers will likely result in energy penalties too severe to produce economic benefits, even at low fuel costs.

14-2

SUMMARY

A summary of the information provided in previous chapters is provided in Table 15-1 and Table

15-2.

15-1

Summary

Table 15-1

Summary Table (1 of 2)

Case

Fuel

PRB (% wt.)

Petcoke (% wt.)

PRB (% heat input)

Petcoke (% heat input)

HHV (Btu/lb)

Capital Cost (2006 USD)

EPC Capital Cost

Owner's Costs

Total Project Cost

EPC Capital Cost, $/kW (73°F Ambient)

Total Project Cost, $/kW (73°F Ambient)

Performance

43°F Dry Bulb, 40°F Wet Bulb

Gross Plant Output, MW

Auxiliary Load, MW

Net Plant Output, MW

Net Plant Heat Rate, Btu/kWh (HHV)

73°F Dry Bulb, 69°F Wet Bulb

Gross Plant Output, MW

Auxiliary Load, MW

Net Plant Output, MW

Net Plant Heat Rate, Btu/kWh (HHV)

93°F Dry Bulb, 77°F Wet Bulb

Gross Plant Output, MW

Auxiliary Load, MW

Net Plant Output, MW

Net Plant Heat Rate, Btu/kWh (HHV)

O&M Cost (2006 USD)

Fixed O&M, $/kW-yr

Variable O&M, $/MWh

Total O&M Cost, $/Year (85% CF)

100% PRB

100%

8,156

$1,318,980,000

$155,240,000

$1,474,220,000

$2,390

$2,670

736.6

137.4

599.2

9,090

709.9

156.8

553.0

9,220

681.5

153.2

528.4

9,350

Base Cases

IGCC

50% PRB / 50% Petcoke

50%

36%

64%

11,194

$1,287,540,000

$139,500,000

$1,427,040,000

$2,330

$2,580

734.2

137.2

597.0

8,950

711.1

158.0

553.0

9,070

682.6

154.5

528.2

9,210

SCPC

100% PRB

100%

8,156

$1,072,580,000

$129,760,000

$1,202,340,000

$1,950

$2,190

623.3

65.4

557.8

9,030

614.5

64.5

550.0

9,150

613.2

64.4

548.8

9,170

Capture Cases

IGCC

100% PRB IGCC

SCPC

100% PRB

100%

8,156

$179,220,000 (Note 1)

$17,960,000 (Note 1)

$197,180,000 (Note 1)

$3,630 (Note 1)

$4,040 (Note 1)

Not Evaluated

630.1

216.8

413.3

12,800

Not Evaluated

100%

8,156

$269,430,000 (Note 1)

$26,570,000 (Note 1)

$296,000,000 (Note 1)

$3,440 (Note 1)

$3,840 (Note 1)

Not Evaluated

521.4

131.6

389.8

12,910

Not Evaluated

$25.19

$5.95

$38,426,700

$25.19

$5.66

$37,245,400

$20.68

$4.60

$30,209,800

$34.74

$8.55

$40,661,400

$31.19

$6.97

$32,563,000

Availability Factor 85% 85% 90% Not Evaluated Not Evaluated

Economic Analysis

Capacity Factor

20-year levelized busbar cost, $/MWh (2006 Real $)

Avoided CO

Cost, $/Mt CO

avoided

85%

$45.03

N/A

85%

$40.89

N/A

85%

$39.28

N/A

$65.41

$26.28

N/A

$62.00

$29.64

Notes:

1) CO

15-2

Summary

Table 15-2

Summary Table (2 of 2)

Case

NO x

Emissions lb/MMBtu (HHV) ppmvd @ 15% O

2 lb/MWh (net)

Emissions lb/MMBtu (HHV) lb/MWh (net)

Emissions (front half) lb/MMBtu (HHV) lb/MWh (net)

CO lb/MMBtu (HHV) ppmvd lb/MWh (net)

2 lb/MMBtu (HHV) lb/MWh (net)

% Removal lb/TBtu (HHV) lb/MWh (net)

100% PRB

0.063

0.581

0.019

0.173

0.007

0.065

0.037

0.337

215

1,985

90%

0.778

7.17E-06

Base Cases

IGCC

50% PRB / 50% Petcoke

0.062

0.562

0.023

0.210

0.007

0.065

0.036

0.337

213

1,934

90%

0.496

4.50E-06

SCPC

100% PRB

0.050

N/A

0.458

0.060

0.549

0.015

0.137

0.150

N/A

1.373

215

1,967

70%

2.315

2.12E-05

Capture Cases

IGCC

100% PRB IGCC

SCPC

100% PRB

0.061

0.781

0.004

0.051

0.007

0.090

0.035 (Note 1)

25 (Note 1)

0.448 (Note 1)

276

90%

0.778

9.96E-06

0.045

N/A

0.581

0.0003

0.003

0.015

0.194

0.150

N/A

1.937

278

70%

2.315

2.99E-05

Plant Cooling Requirements, MMBtu/hr (@ 73°F)

Steam Cycle Cooling Requirement, MMBtu/hr

2,141

1,480

661

2,179

1,480

699

2,490

2,300

190

2,101

1,120

981

3,330

1,354

1,976 BOP Auxiliary Cooling Requirement, MMBtu/hr

Total Plant Makeup Water Requirement

GPM (@ 73°F)

Acre-ft/year (@ 85% CF)

4,980

6,830

5,231

7,170

5,800

7,950

6,147

8,430

7,757

10,640

Notes:

1) GE is currently in the process of developing tools to accurately predict CO emissions for high hydrogen fuels. It is estimated that CO emissions will be less than shown for IGCC CO

capture technology, however to what extent is unknown at this time.

15-3

Summary

Of the three alternatives evaluated, SCPC technology provides the lowest busbar cost based on this analysis. SCPC technology provides a $5.75/MWh (approximately 13%) lower busbar cost than a comparable IGCC unit when operating on 100% PRB fuel. The 100% PRB SCPC also provides a $1.61/MWh (approximately 4%) lower busbar cost than the IGCC operating on 50%

PRB / 50% petcoke. Of the two IGCC alternatives, the fuel blend case provides the lowest busbar cost, provided that a long-term petcoke supply that meets plant specifications can be found for the project at a reasonable cost.

The SCPC Unit provides a lower capital cost, lower O&M, better performance, and higher availability factor than the IGCC. Although the heat rate for the 50% PRB / 50% petcoke IGCC option is better than the 100% PRB SCPC option (except at 93°F ambient), this difference could likely be overcome by specifying a fuel blend for the SCPC option.

IGCC has an advantage in terms of SO

, PM

, and mercury emissions, however using the emissions allowance costs provided in Chapter 8, these lower emissions are not enough to overcome the disadvantages discussed above.

In an effort to reduce greenhouse gases, some form of CO

2 legislation may be passed in the future. At this point in time, it is uncertain what form this legislation will take, but it is logical to assume that CO

2 regulations would provide an incentive for CO

reduction from power plants.

The installation of CO

capture equipment as a retrofit for both of these technologies results in a very significant decrease in net plant output, a significant increase in net plant heat rate, and a significant increase in water consumption. All of these factors result in an increase of the 20year levelized busbar cost by approximately 45% for the IGCC and 58% for the SCPC post CO

2 capture.

SCPC technology still provides the lowest busbar cost after CO

capture retrofit, although by less of a gap than pre-CO

capture. The avoided cost of CO

capture is less for an IGCC implying that IGCC technology is the more economical choice for retrofit of CO

capture technology, however the lower initial capital cost (pre-capture) of SCPC technology still results in an overall lower busbar cost for SCPC technology.

It is recommended that additional studies be performed if IGCC, SCPC, or CO

capture technology is of interest to the Owner:

• SCR for IGCC technology.

• Two-pressure vs. three-pressure HRSG for IGCC technology.

• Other multi-pollutant flue gas clean-up systems such as J-Power’s ReACT system and

Powerspan’s ECO system for SCPC technology.

• More efficient steam cycle for SCPC technology.

15-4

Summary

• Inlet air cooling methods (chilling vs. evaporative cooling) in conjunction with evaluation of air-side integration for IGCC technology.

• IGCC and SCPC CO

capture pre-investment options.

• Other SCPC CO

capture technologies such as MHI’s KS-1 process.

• Evaluation of gasifiers from other manufacturers that that may be better suited for CO

2 capture.

• Heat recovery from CO

compression.

• Raw water availability study, which may result in different water treatment requirements.

• More detailed studies incorporating gasifier and gas turbine vendor involvement.

Changes in market conditions, improvements in IGCC technology, different fuel specifications, or CO

purity specifications could be enough to swing the economics in favor of IGCC.

Therefore it is recommended that utilities consider IGCC technology for future generation needs.

15-5

PROCESS FLOW DIAGRAMS

A-1

DEMINERALIZED

WATER

100

611

102

GCT-PFD-2

SYNGAS SATURATOR

MAKEUP

103

SYNGAS FROM

GASIFIER

SYNGAS

COOLER

605

504

SATURATOR PURGE

GCT-PFD-2

SOUR WATER

STRIPPER PURGE

HP BFW

40-1&2-SGT-TNK-001

SYNGAS WASH

TOWERS

105

101

TO RECOVERED WATER

FLASH DRUM

GCT-PFD-2

104

NOTES:

CONDENSATE

CIRC. WATER

204

HP BFW

201

40-1&2-SGT-HTX-003

HYDROLYSIS

PREHEATERS

107

40-1&2-SGT-HTX-002

HYDROLYSIS

INTERCHANGERS

205

40-1&2-SGT-TNK-004

COS/HCN HYDROLYSIS

REACTORS

NO. DATE BY REVISION

A 6/7/06 JAJ INTERNAL REVIEW

B 6/16/06 JAJ INTERNAL REVIEW

C 7/24/06 JAJ INTERNAL REVIEW

D 7/31/06 JAJ INTERNAL REVIEW

E 8/11/06 JAJ FINAL

206

OXYGEN

TO SRU

FROM SOUR

WATER STRIPPER

GCT-PFD-2

301

403

SYNGAS TO

SATURATOR

GCT-PFD-2

40-1&2-SGT-HTX-004

SYNGAS

INTERCHANGERS

302

401

400

402

IP STEAM

SYNGAS TO

COAL/COKE DRYING

313

310

502

303

304

40-1&2-SGT-TNK-005

WATER KNOCKOUT

DRUMS

40-1&2-SGT-HTX-005

FIRST STAGE

SYNGAS CONDENSORS

40-1&2-SGT-HTX-006

SECOND STAGE

SYNGAS CONDENSORS

306

305

40-1&2-SGT-PMP-001A/B

SOUR WATER PUMPS

SELEXOL

AGR

307

40-1&2-SGT-HTX-001

MERCURY REMOVAL

PREHEATERS

308

309

SRU / TGTU

IP BFW

IP STEAM CONDENSATE

316

IP BFW

312

314

CIRC. WATER

SULFUR

40-1&2-SGT-TNK-002

MERCURY ABSORBENT

BEDS

315

GCT-PFD-2

SOUR WATER

TO EFFLUENT

HEAT EXCHANGER

40-1&2-SGT-HTX-015

MERCURY REMOVAL

AFTERCOOLERS

311

HP STEAM

HP BFW

LP STEAM

CONDENSATE

SW TO SOUR

WATER STRIPPER

GCT-PFD-2 date

07-JUN-06 designed

T_McCALL detailed checked

CPS / EPRI IGCC FEASIBILITY

STUDY

PROCESS FLOW DIAGRAM

GAS COOLING AND TREATMENT

project contract

42127 drawing rev

GCT-PFD-1 E

SYNGAS FROM

INTERCHANGERS

GCT-PFD-1

DEMINERALIZED

WATER

GCT-PFD-1

403

611

FROM SYNGAS

WASH TOWERS

GCT-PFD-1

104

40-0-SGT-HTX-013

FLASHED WATER

CONDENSER

705

701

702

40-0-SGT-TNK-008

RECOVERED WATER

FLASH DRUM

703

40-0-SGT-HTX-012

RECOVERED WASH

WATER EXCHANGER

40-0-SGT-PMP-005A/B

RECOVERED WASH

WATER PUMPS

IP STEAM

707

706

40-0-SGT-JET-1

FLASHED WATER

STEAM EJECTOR

708

704

40-0-SGT-FLT-001

RECOVERED WASH

WATER FILTER

712

TO COOLING TOWER

711

SOLIDS TO

LANDFILL

610

SW FROM

TGTU

GCT-PFD-1

311

40-0-SGT-TNK-009

FLASH WATER

CONDENSATE DRUM

TO SYNGAS

WASH TOWER

GCT-PFD-1

504

FROM SOUR

WATER PUMPS

GCT-PFD-1

308

709

40-0-SGT-PMP-006A/B

FLASHED WATER

CONDENSATE PUMP

710

40-0-SGT-HTX-009

SOUR WATER

FEED / EFFLUENT

EXCHANGER

501

503

40-0-SGT-TNK-007

SOUR WATER

STRIPPER

40-0-SGT-PMP-004A/B

SOUR WATER STRIPPER

BOTTOM PUMPS

40-1&2-SGT-HTX-007

SWEET SYNGAS

HEATER

601

HP BFW

602

SYNGAS TO

GAS TURBINES

608

40-1&2-SGT-TNK-006

SYNGAS SATURATOR

HP BFW

607

HP BFW

40-1&2-SGT-HTX-008

SATURATOR

HEATER

603

604

40-1&2-SGT-PMP-002A/B

SATURATOR CIRCULATION

PUMPS

606

605

SATURATOR PURGE

TO SYNGAS WASH

TOWER

GCT-PFD-1

NO. DATE BY REVISION

A 6/7/06 JAJ INTERNAL REVIEW

B 6/16/06 JAJ INTERNAL REVIEW

C 7/24/06 JAJ INTERNAL REVIEW

D 7/31/06 JAJ INTERNAL REVIEW

E 8/11/06 JAJ FINAL

502

506

505

40-0-SGT-PMP-003A/B

SOUR WATER PUMP

AROUND PUMPS

40-0-SGT-HTX-011

SOUR WATER

REBOILER

LP STEAM

CONDENSATE

40-0-SGT-HTX-010

SOUR WATER PUMP

AROUND COOLER

TO SULFUR

RECOVERY UNIT

GCT-PFD-1 date

07-JUN-06 designed

T_McCALL detailed checked

JAJ

CPS / EPRI IGCC FEASIBILITY

STUDY

PROCESS FLOW DIAGRAM

GAS COOLING AND TREATMENT

project contract

42127 drawing rev

GCT-PFD-2 E

TAIL GAS

FROM TGTU

GCT-PFD-3

DEMINERALIZED

WATER

SATURATOR

PURGE

GCT-PFD-4

SOUR WATER

STRIPPER PURGE

GCT-PFD-4

100

605

SYNGAS FROM

GASIFIER

102

IP STEAM

504

103

SYNGAS

COOLER

40-1&2-SGT-TNK-001

SYNGAS WASH

TOWERS

101

105

316

SW TO SOUR

WATER STRIPPER

GCT-PFD-4

40-1&2-SGT-PMP-101A/B

KNOCKOUT WATER PUMPS

207

321

201

405

106

208

40-1&2-SGT-HTX-103

ND STAGE SOUR GAS

SHIFT OUTLET

INTERCHANGERS

202

40-1&2-SGT-HTX-101

STAGE SOUR GAS

SHIFT INLET

INTERCHANGERS

209

203

204

HP BFW

40-1&2-SGT-HTX-120

STAGE SOUR GAS

SHIFT PREHEATERS

TO RECOVERED WATER

FLASH DRUM

GCT-PFD-4

104

40-1&2-SGT-TNK-103

WATER FLASH

DRUMS

322

206

40-1&2-SGT-TNK-101

STAGE SOUR GAS

SHIFT REACTORS

40-1&2-SGT-TNK-102

ND STAGE SOUR GAS

SHIFT REACTORS

HP BFW

319

320

40-1&2-SGT-HTX-114

RECYCLE STEAM

GENERATORS

HP BFW

205

318

40-1&2-SGT-HTX-102

STAGE SOUR GAS

SHIFT OUTLET

INTERCHANGERS

401

40-0-SGT-HTX-012

WASTEWATER

INTERCHANGER

317

309

315

323

306

40-1&2-SGT-HTX-109

SOUR GAS

CONDENSERS

311

308

40-1&2-SGT-TNK-005

WATER KNOCKOUT

DRUMS

CONDENSATE

307

40-1&2-SGT-HTX-110

SOUR GAS

CONDENSERS

CIRC. WATER

40-1&2-SGT-HTX-111

SOUR GAS

CONDENSERS

312

40-1&2-SGT-TNK-002

MERCURY ADSORBENT

BEDS

313

40-1&2-SGT-HTX-015

MERCURY REMOVAL

AFERCOOLERS

CIRC. WATER

314

CIRC. WATER

400

614

SELEXOL

AGR

40-1&2-SGT-HTX-104

SATURATOR HEATERS

301

302

40-1&2-SGT-HTX-105

SOUR GAS

CONDENSERS

303

40-1&2-SGT-HTX-106

SOUR GAS

CONDENSERS

304

40-1&2-SGT-HTX-107

SOUR GAS

CONDENSERS

305

40-1&2-SGT-HTX-108

SOUR GAS

CONDENSERS

406 407

40-0-SGT-CMP-101A/B/C/D

CO2 COMPRESSOR

W / INTERCOOLERS

404

414

OXYGEN

TO SRU

OXYGEN

615

609

607

611

GCT-PFD-4

DEMIN. WATER

TO HTX-012

608

606

RECIRC WATER

TO SATURATOR

GCT-PFD-4

RECIRC WATER

FROM SATURATOR

GCT-PFD-4

SYNGAS TO

SATURATOR

GCT-PFD-4

403

616

HP NITROGEN TO

SATURATOR.

GCT-PFD-4

610

DEMIN. WATER

FROM HTX-012

GCT-PFD-4

SRU / TGTU

417

402

613

413

HP NITROGEN

SYNGAS TO

COAL/COKE DRYING

CO2 TO PIPELINE

SULFUR

405

TAIL GAS TO

SHIFT REACTORS

GCT-PFD-3

416

SW TO SOUR

WATER STRIPPER

GCT-PFD-4

NO. DATE BY REVISION

A 6/7/06 JAJ INTERNAL REVIEW

B 8/11/06 JAJ INTERNAL REVIEW

C 8/28/06 JAJ INTERNAL REVIEW

D 9/14/06 TMA FINAL

- DENOTES ORIGINAL EQUIPMENT

REUSED FOR CO2 CAPTURE.

date

07-JUN-06 designed

T_McCALL detailed checked

CPS / EPRI IGCC FEASIBILITY

STUDY

PROCESS FLOW DIAGRAM

GAS COOLING AND TREATMENT - CO2 CAPTURE

project contract

42127 drawing rev

HP NITROGEN

FROM HTX-106

GCT-PFD-3

RECIRC WATER

FROM HTX-104

GCT-PFD-3

SYNGAS FROM

INTERCHANGERS

GCT-PFD-3

DEMIN. WATER

GCT-PFD-3

616

608

403

611

FROM SYNGAS

WASH TOWERS

GCT-PFD-3

DEMIN. WATER

TO HTX-108

GCT-PFD-3

104

610

701

702

40-0-SGT-TNK-008

RECOVERED WATER

FLASH DRUM

703

40-0-SGT-HTX-012

RECOVERED WASH

WATER EXCHANGER

704

40-1&2-SGT-FLT-101A/B

WASH WATER FILTERS

712

TO COOLING TOWER

711

SOLIDS TO

COAL PILE

40-0-SGT-HTX-013

FLASHED WATER

CONDENSER

705

IP STEAM

40-1&2-SGT-PMP-005A/B

RECOVERED WASH

WATER PUMPS

40-0-SGT-JET-1

FLASHED WATER

STEAM EJECTOR

707

706

708

SW FROM

TGTU

GCT-PFD-3

416

40-0-SGT-TNK-009

FLASH WATER

CONDENSATE DRUM

TO SYNGAS

WASH TOWER

GCT-PFD-3

504

SOUR WATER

FROM TNK-005

GCT-PFD-3

310

709

40-0-SGT-PMP-006A/B

FLASHED WATER

CONDENSATE PUMP

710

40-0-SGT-HTX-009

SOUR WATER

FEED / EFFLUENT

EXCHANGER

501

503

40-0-SGT-TNK-007

SOUR WATER

STRIPPER

40-0-SGT-PMP-004A/B

SOUR WATER STRIPPER

BOTTOM PUMPS

601

40-1&2-SGT-TNK-006

SYNGAS SATURATORS

HP BFW

602

40-1&2-SGT-HTX-006

SWEET SYNGAS

HEATERS

SYNGAS TO

GAS TURBINES

HP BFW

603

502

604

40-1&2-SGT-PMP-002A/B

SATURATOR CIRCULATION

PUMPS

506

505

40-0-SGT-PMP-003A/B

SOUR WATER PUMP

AROUND PUMPS

40-0-SGT-HTX-011

SOUR WATER

REBOILER

LP STEAM

CONDENSATE

606

605

40-0-SGT-HTX-010

SOUR WATER PUMP

AROUND COOLER

RECIRC WATER

TO HTX-104

GCT-PFD-3

SAT. PURGE TO

WASH TOWER

GCT-PFD-3

TO SULFUR

RECOVERY UNIT

GCT-PFD-3

NO. DATE BY REVISION

A 9/14/06 TMA FINAL date

07-JUN-06 designed

T_McCALL detailed checked

JAJ

CPS / EPRI IGCC FEASIBILITY

STUDY

PROCESS FLOW DIAGRAM

GAS COOLING AND TREATMENT

project contract

42127 drawing rev

SYNGAS TREATING AREA

43F PRB

Table 1

Component Balance

9/14/2006

Project No: 42127

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

Component lb-moles/hr

NH3

NO2

SO2

Sulfur

CH4

CO2

COS

H2O

H2S

HCN

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

100

Total Makeup

Demineralized

Water

101

Raw Syngas

102

Demin Water to

Wash Tower

103

Water to Wash

Tower

104

Wash Tower

Bottoms Stream

105

Wash Tower

Overhead Vapor

107

Hydrolysis

Reactor Feed

(prior to preheat)

201

Hydrolysis

Reactor Feed

(after preheat)

204

Hydrolysis

Reactor Feed

14,147

254,865

510

62.30

0.684

1.031

0.363

18.0

---

100

254,865

14,147

0.0

14,147.3

0.0

---

42,556

901,724

12,945

1.16

0.023

0.347

0.039

21.19

540

450

901,724

42,556

8.3

25,497.0

1,133.3

5.5

11,397.9

1,758.4

71.5

2.0

1.9

2,268.0

0.0

412.5

0.0

500

100

117,000

6,495

0.0

6,494.6

0.0

6,495

117,000

234

62.35

0.680

1.030

0.363

18.0

---

11,311

203,773

414

61.42

0.485

1.032

0.376

18.0

---

480

135

203,773

11,311

0.0

11,310.9

0.0

0.1

0.0

520

280

172,170

9,555

1.1

9,549.5

0.3

0.1

0.0

2.1

1.2

0.0

0.4

0.2

0.0

9,555

172,170

375

57.22

0.199

1.076

0.397

18.0

---

44,588

943,246

11,026

1.43

0.020

0.351

0.032

21.15

519

260

943,246

44,588

8.3

25,506.6

1,341.0

5.5

11,440.3

3,522.5

74.6

1.9

1.6

2,273.3

0.0

412.5

0.0

---

44,313

933,327

10,955

1.42

0.020

0.352

0.033

21.06

519

260

933,327

44,313

8.3

25,495.0

1,132.2

5.5

11,396.8

3,519.9

71.2

1.9

1.6

2,267.8

0.0

412.5

0.0

---

44,588

943,246

12,499

1.26

0.021

0.350

0.035

21.15

518

350

943,246

44,588

8.3

25,506.6

1,341.0

5.5

11,440.3

3,522.5

74.6

1.9

1.6

2,273.3

0.0

412.5

0.0

517

425

943,246

44,588

8.3

25,506.6

1,341.0

5.5

11,440.3

3,522.5

74.6

1.9

1.6

2,273.3

0.0

412.5

0.0

---

44,588

943,246

13,721

1.15

0.023

0.351

0.038

21.15

Material Balance SGT PRB 25% H2S 16 Sep.xls Mat Bal Page 1 of 7

SYNGAS TREATING AREA

43F PRB

Table 1

Component Balance

9/14/2006

Project No: 42127

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

Component lb-moles/hr

NH3

NO2

SO2

Sulfur

CH4

CO2

COS

H2O

H2S

HCN

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

205

Hyfdrolysis

Reactor Effluent

206

Hydrolysis

Reactor Effluent

(after heat exchange)

301

Sour Syngas to

Interchanger

302

Sour Syngas from Interchanger

303

Syngas from First

Stage

Condensation

304

Syngas from

Second Stage

Condensation

305

Syngas to

Mercury Removal

Preheat

306

Sour Water from

Sour Syngas

Condensation

307

Sour Water

Recycle to

Syngas

Condensation

---

44,588

943,246

13,995

1.12

0.023

0.351

0.038

21.15

507

425

943,246

44,588

8.3

25,506.6

1,348.0

0.3

11,442.1

3,513.6

79.9

0.0

3.4

2,273.3

0.0

412.5

0.0

---

44,588

943,246

12,551

1.25

0.021

0.350

0.035

21.15

506

335

943,246

44,588

8.3

25,506.6

1,348.0

0.3

11,442.1

3,513.6

79.9

0.0

3.4

2,273.3

0.0

412.5

0.0

506

273

963,246

45,698

8.3

25,506.6

1,348.4

0.3

11,442.1

4,621.9

79.9

0.0

4.1

2,273.4

0.0

412.5

0.0

1,153

57.44

0.205

1.072

0.397

18.0

45,634

962,092

11,754

1.36

0.020

0.354

0.033

21.08

44,031

933,209

11,017

1.41

0.019

0.349

0.032

21.19

1,667

30,036

58.19

0.230

1.061

0.397

18.0

505

248

963,246

45,698

8.3

25,506.6

1,348.4

0.3

11,442.1

4,621.9

79.9

0.0

4.1

2,273.4

0.0

412.5

0.0

502

110

963,246

45,698

8.3

25,506.6

1,348.4

0.3

11,442.1

4,621.9

79.9

0.0

4.1

2,273.4

0.0

412.5

0.0

41,210

882,362

8,353

1.76

0.017

0.340

0.028

21.41

4,487

80,884

162

62.07

0.652

1.030

0.367

18.0

---

41,176

881,735

8,209

1.79

0.017

0.340

0.028

21.41

501

100

881,735

41,176

8.3

25,506.4

1,346.8

0.3

11,442.1

104.9

79.6

0.0

1.4

2,273.3

0.0

412.5

0.0

41,176

881,735

8,209

1.79

0.017

0.340

0.028

21.41

4,522

81,511

163

62.33

0.718

1.029

0.363

18.0

501

100

963,246

45,698

8.3

25,506.6

1,348.4

0.3

11,442.1

4,621.9

79.9

0.0

4.1

2,273.4

0.0

412.5

0.0

1,110

20,000

62.33

0.718

1.029

0.363

18.0

---

521

100

20,000

1,110

0.0

1,108.3

0.1

0.0

0.4

0.0

0.6

0.0

4,522

81,511

163

62.33

0.718

1.029

0.363

18.0

1.79

0.017

0.340

0.028

21.41

501

100

81,511

4,522

0.1

4,517.0

0.3

0.0

0.2

1.6

0.0

2.6

0.1

0.0

Material Balance SGT PRB 25% H2S 16 Sep.xls Mat Bal Page 2 of 7

SYNGAS TREATING AREA

43F PRB

Table 1

Component Balance

9/14/2006

Project No: 42127

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

Component lb-moles/hr

NH3

NO2

SO2

Sulfur

CH4

CO2

COS

H2O

H2S

HCN

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

308

Sour Water to

Elluent Heat

Exchange

309

Sour Gas to

Sulrur Recovery

Unit (SRU)

310

Recycle Gas from SRU

311

Sour Water from

Tail Gas Treating

(TGTU) to Sour

Water Stripper

312

Sulfur Product

313

Oxygen to SRU

314

Syngas to

Mercury Removal

315

Syngas from

Mercury Removal

316

Syngas to AGR

---

315

10,316

784

0.22

0.016

0.242

0.014

32.70

100

10,316

315

0.0

14.3

0.0

1.9

0.0

127.5

80.8

0.1

12.1

0.0

78.6

0.0

3,412

61,511

123

62.33

0.718

1.029

0.363

18.0

1.79

0.017

0.340

0.028

21.41

519

100

61,511

3,412

0.1

3,408.7

0.2

0.0

0.1

1.2

0.0

2.0

0.1

0.0

---

275

9,919

2.54

0.023

0.278

0.024

36.02

556

303

9,919

275

0.0

5.5

0.0

11.6

208.8

0.0

43.5

2.6

3.4

0.0

104

1,155

0.06

0.009

1.354

0.086

5.17

1,155

62.18

0.651

1.031

0.365

18.0

0.0

64.1

0.0

100

2,293

---

32.1

0.0

71.5

100

1,568

0.53

0.022

0.223

0.016

31.80

---

0.0

13.2

46.8

0.0

500

105

881,735

41,176

---

41,176

881,735

8,303

1.77

0.017

0.340

0.028

21.41

8.3

25,506.4

1,346.8

0.3

11,442.1

104.9

79.6

0.0

1.4

2,273.3

0.0

412.5

0.0

---

41,176

881,735

8,336

1.76

0.017

0.340

0.028

21.41

498

105

881,735

41,176

8.3

25,506.4

1,346.8

0.3

11,442.1

104.9

79.6

0.0

1.4

2,273.3

0.0

412.5

0.0

497

100

881,735

41,176

8.3

25,506.4

1,346.8

0.3

11,442.1

104.9

79.6

0.0

1.4

2,273.3

0.0

412.5

0.0

---

41,176

881,735

8,275

1.78

0.017

0.340

0.028

21.41

Material Balance SGT PRB 25% H2S 16 Sep.xls Mat Bal Page 3 of 7

SYNGAS TREATING AREA

43F PRB

Table 1

Component Balance

9/14/2006

Project No: 42127

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

Component lb-moles/hr

NH3

NO2

SO2

Sulfur

CH4

CO2

COS

H2O

H2S

HCN

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

400

Sweet Syngas from Selexol

401

Sweet Syngas to

Syngas

Interchanger

402

Sweet Syngas to

Coal Drying

403

Sweet Syngas to

Saturator

501

Primary Sour

Water Stripper

Feed

502

Sopur Water

Stripper

Overhead Vapor to SRU

503

Recovered Water from Sour Water

Stripper to heat exchange

504

Recovered Water from Sour Water

Stripper to Wash

Tower

505

Pump Around from SWS to Air

Cooler

---

38,138

813,369

7,776

1.74

0.017

0.341

0.028

21.33

490

100

813,369

38,138

7.7

23,688.3

1,181.7

0.1

10,668.5

97.9

0.9

0.0

1.3

2,108.5

0.0

383.3

0.0

---

40,860

871,419

8,331

1.74

0.017

0.341

0.028

21.33

490

100

871,419

40,860

8.3

25,378.9

1,266.0

0.2

11,430.0

104.9

1.0

0.0

1.4

2,259.0

0.0

410.6

0.0

---

2,722

58,050

555

1.74

0.017

0.341

0.028

21.33

490

100

58,050

2,722

0.6

1,690.6

84.3

0.0

761.4

7.0

0.1

0.0

0.1

150.5

0.0

27.4

0.0

489

227

813,369

38,138

7.7

23,688.3

1,181.7

0.1

10,668.5

97.9

0.9

0.0

1.3

2,108.5

0.0

383.3

0.0

---

38,138

813,369

9,639

1.41

0.020

0.338

0.033

21.33

3,412

61,511

129

59.59

0.301

1.044

0.392

18.0

---

500

200

61,511

3,412

0.1

3,408.7

0.2

0.0

0.1

1.2

0.0

2.0

0.1

0.0

184

292

---

292

0.11

0.013

0.341

0.019

24.29

2.2

0.2

0.0

1.2

3.2

0.5

0.1

0.0

2.2

2.4

0.0

4,517

81,367

175

58.05

0.224

1.064

0.397

18.0

---

481

253

81,367

4,517

0.0

4,516.5

0.0

0.1

0.0

4,517

81,367

168

60.22

0.345

1.040

0.388

18.0

---

480

203

81,367

4,517

0.0

4,516.5

0.0

0.1

0.0

4,517

81,367

168

60.22

0.345

1.040

0.388

18.0

---

480

178

81,367

4,517

0.0

4,516.5

0.0

0.1

0.0

Material Balance SGT PRB 25% H2S 16 Sep.xls Mat Bal Page 4 of 7

SYNGAS TREATING AREA

43F PRB

Table 1

Component Balance

9/14/2006

Project No: 42127

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

Component lb-moles/hr

NH3

NO2

SO2

Sulfur

CH4

CO2

COS

H2O

H2S

HCN

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

506

Pump Around from Air Cooler to

SWS

601

Saturator

Overhead Vapor

602

Syngas to Gas

Turbines

603

Saturator

Bottoms Liquid

604

Saturator

Bottoms Pump

Discharge

605

Saturator Liquid

Purge to Wash

Tower

606

Saturetor Bottms

Circulation after

Purge

607

Saturator

Circulation Liquid after Make-up

608

Saturator

Circulation Liquid after Satiratpr

Heater

4,517

81,367

168

60.22

0.345

1.040

0.388

18.0

---

480

178

81,367

4,517

0.0

4,516.5

0.0

0.1

0.0

480

303

947,014

45,557

7.7

23,688.2

45,557

947,014

12,805

1.23

0.020

0.365

0.033

20.79

---

1,181.6

0.1

10,668.5

7,517.7

0.9

0.0

2,108.5

0.0

383.3

0.0

479

405

947,014

45,557

7.7

23,688.2

1,181.6

0.1

10,668.5

7,517.7

0.9

0.0

2,108.5

0.0

383.3

0.0

45,557

947,014

14,659

1.08

0.021

0.365

0.036

20.79

---

481

223

1,125,907

62,483

4.1

62,459.2

0.0

8.2

9.4

0.0

---

62,483

1,125,907

2,382

58.93

0.262

1.052

0.395

18.0

1.3

0.9

0.0

516

223

1,125,907

62,483

---

62,483

1,125,907

2,382

58.93

0.262

1.052

0.395

18.0

0.0

8.2

9.4

0.0

4.1

62,459.2

0.0

1.3

0.9

0.0

300

5,406

58.93

0.262

1.052

0.395

18.0

---

516

223

5,406

300

0.0

299.9

0.0

516

223

1,120,501

62,183

4.1

62,159.3

0.0

8.1

9.3

0.0

1.3

0.9

0.0

500

217

1,258,366

69,836

4.1

69,812.0

0.0

8.1

9.3

0.0

1.3

0.9

0.0

490

335

1,258,366

69,836

4.1

69,812.0

0.0

8.1

9.3

0.0

1.3

0.9

0.0

---

62,183

1,120,501

2,371

58.93

0.262

1.052

0.395

18.0

---

69,836

1,258,366

2,654

59.11

0.271

1.050

0.394

18.0

69,836

1,258,366

2,830

55.43

0.160

1.111

0.394

18.0

---

Material Balance SGT PRB 25% H2S 16 Sep.xls Mat Bal Page 5 of 7

SYNGAS TREATING AREA

43F PRB

Table 1

Component Balance

9/14/2006

Project No: 42127

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

Component lb-moles/hr

NH3

NO2

SO2

Sulfur

CH4

CO2

COS

H2O

H2S

HCN

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

610

Demin Water

Make-up to

Saturator (after heat exchange)

611

Demin Water

Make-up to

Saturator (before heat exchange)

701

Flashed Vapor from Wash

Tower Bottoms

Flash

702

Flashed Liquid from Wash

Tower Bottoms

Flash

703

Recovered Wash

Water from Flash

704

Cooled

Recovered Water from Flash

705

Recovered Wash

Water from Flash after Air Cooler

706

Vapors to Jet

Ejector

707

Steam to Jet

Ejector

500

165

137,865

7,653

137,865

284

60.58

0.379

1.037

0.385

18.0

---

0.0

7,652.7

0.0

500

100

137,865

7,653

137,865

276

62.35

0.680

1.030

0.363

18.0

---

0.0

7,652.7

0.0

177

19,082

1,057

---

1,057

19,082

17,105

0.02

0.009

0.451

0.013

18.05

1.1

1,051.8

0.3

0.1

0.0

2.1

1.2

0.0

0.3

0.2

0.0

177

153,088

8,498

0.02

0.009

0.451

0.013

18.05

8,498

153,088

317

60.19

0.349

1.041

0.387

18.0

0.0

8,497.6

0.0

0.1

0.0

177

153,088

8,498

153,088

317

60.19

0.349

1.041

0.387

18.0

---

0.0

8,497.6

0.0

0.1

0.0

118

153,088

8,498

153,088

309

61.81

0.565

1.032

0.370

18.0

---

0.0

8,497.6

0.0

0.1

0.0

1,047

18,855

60.92

0.426

1.036

0.381

18.0

227

165

0.02

0.011

0.363

0.018

21.75

150

19,082

1,057

1.1

1,051.8

0.3

0.1

0.0

2.1

1.2

0.0

0.3

0.2

0.0

150

227

165

0.02

0.011

0.363

0.018

21.75

---

0.0

2.1

1.1

0.0

1.1

5.6

0.2

0.0

0.2

0.0

615

491

500

0.0

27.8

0.0

---

500

1.29

0.018

0.580

0.029

18.02

Material Balance SGT PRB 25% H2S 16 Sep.xls Mat Bal Page 6 of 7

SYNGAS TREATING AREA

43F PRB

Table 1

Component Balance

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

Component lb-moles/hr

NH3

NO2

SO2

Sulfur

CH4

CO2

COS

H2O

H2S

HCN

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

708

Jet Ejector

Effluent Vapor to

SWS

709

Condensate

Recovered from

Vacuum Flash

710

Recovered

Condensate to

SWS

711

Solids from

Candle Filers

Recovered in

Wash Tower

712

Recovered Wash

Water to

Disposal

326

727

---

727

776

0.02

0.012

0.433

0.019

19.04

0.0

0.2

0.0

1.1

33.4

0.2

0.0

2.1

1.1

0.0

1,047

18,855

60.92

0.426

1.036

0.381

18.0

0.02

0.011

0.363

0.018

21.75

150

18,855

1,047

0.0

1,046.2

0.0

0.1

0.0

0.3

0.0

1,047

18,855

60.93

0.426

1.036

0.381

18.0

---

150

18,855

1,047

0.0

1,046.2

0.0

0.1

0.0

0.3

0.0

Approximately

110 lb/day of solids will be removed by the filters and sent to the coal pile.

8,498

153,088

309

61.81

0.565

1.032

0.370

18.0

---

118

153,088

8,498

0.0

8,497.6

0.0

0.1

0.0

Material Balance SGT PRB 25% H2S 16 Sep.xls Mat Bal Page 7 of 7

9/14/2006

Project No: 42127

SYNGAS TREATING AREA

43F PRB + PETCOKE

Table 1

Component Balance

9/14/2006

Project No: 42127

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

Component lb-moles/hr

NH3

NO2

SO2

Sulfur

CH4

CO2

COS

H2O

H2S

HCN

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

100

Total Makeup

Demineralized

Water

101

Raw Syngas

102

Demin Water to

Wash Tower

103

Water to Wash

Tower

104

Wash Tower

Bottoms Stream

105

Wash Tower

Overhead Vapor

107

Hydrolysis

Reactor Feed

(prior to preheat)

201

Hydrolysis

Reactor Feed

(after preheat)

204

Hydrolysis

Reactor Feed

13,955

251,395

503

62.30

0.684

1.031

0.363

18.0

---

100

251,395

13,955

0.0

13,954.7

0.0

---

39,203

850,323

11,948

1.19

0.024

0.335

0.038

21.69

540

450

850,323

39,203

7.2

25,424.2

430.6

43.0

9,891.7

646.0

476.1

4.6

1.5

1,880.1

0.0

398.0

0.0

500

100

117,000

6,495

0.0

6,494.6

0.0

6,495

117,000

234

62.35

0.680

1.030

0.363

18.0

---

10,110

182,132

369

61.56

0.508

1.032

0.374

18.0

---

480

130

182,132

10,110

0.0

10,109.7

0.0

0.2

0.0

510

266

146,731

8,142

0.8

8,137.2

1.5

0.3

0.0

1.7

0.4

0.0

0.4

0.1

0.0

8,142

146,731

317

57.64

0.211

1.069

0.397

18.0

---

41,858

909,315

10,365

1.46

0.020

0.340

0.031

21.72

509

246

909,315

41,858

7.2

25,436.1

923.5

43.0

10,030.0

2,624.8

492.5

4.3

1.3

1,897.8

0.0

398.0

0.0

---

41,171

885,724

10,183

1.45

0.020

0.342

0.031

21.51

509

245

885,724

41,171

7.2

25,422.6

430.2

43.0

9,890.9

2,618.5

474.6

4.3

1.3

1,880.0

0.0

398.0

0.0

---

41,858

909,315

11,982

1.26

0.022

0.339

0.034

21.72

508

350

909,315

41,858

7.2

25,436.1

923.5

43.0

10,030.0

2,624.8

492.5

4.3

1.3

1,897.8

0.0

398.0

0.0

507

425

909,315

41,858

7.2

25,436.1

923.5

43.0

10,030.0

2,624.8

492.5

4.3

1.3

1,897.8

0.0

398.0

0.0

---

41,858

909,315

13,149

1.15

0.023

0.340

0.037

21.72

Material Balance SGT PRB + PETOCKE 50% H2S 16 Sep.xls Mat Bal Page 1 of 7

SYNGAS TREATING AREA

43F PRB + PETCOKE

Table 1

Component Balance

9/14/2006

Project No: 42127

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

Component lb-moles/hr

NH3

NO2

SO2

Sulfur

CH4

CO2

COS

H2O

H2S

HCN

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

205

Hyfdrolysis

Reactor Effluent

206

Hydrolysis

Reactor Effluent

(after heat exchange)

301

Sour Syngas to

Interchanger

302

Sour Syngas from Interchanger

303

Syngas from First

Stage

Condensation

304

Syngas from

Second Stage

Condensation

305

Syngas to

Mercury Removal

Preheat

306

Sour Water from

Sour Syngas

Condensation

307

Sour Water

Recycle to

Syngas

Condensation

---

41,858

909,315

13,238

1.14

0.023

0.340

0.037

21.72

505

427

909,315

41,858

7.2

25,436.1

968.5

2.1

10,034.3

2,575.6

533.3

0.1

5.5

1,897.8

0.0

398.0

0.0

---

41,858

909,315

11,671

1.30

0.021

0.339

0.033

21.72

504

324

909,315

41,858

7.2

25,436.1

968.5

2.1

10,034.3

2,575.6

533.3

0.1

5.5

1,897.8

0.0

398.0

0.0

504

261

929,315

42,968

7.2

25,436.1

968.8

2.1

10,034.3

3,682.7

533.8

0.1

6.7

1,897.8

0.0

398.0

0.0

129

2,331

57.80

0.216

1.066

0.397

18.0

42,838

926,984

10,908

1.42

0.020

0.343

0.031

21.64

41,875

909,616

10,442

1.45

0.020

0.340

0.031

21.72

1,093

19,699

58.33

0.236

1.059

0.396

18.0

503

243

929,315

42,968

7.2

25,436.1

968.8

2.1

10,034.3

3,682.7

533.8

0.1

6.7

1,897.8

0.0

398.0

0.0

500

110

929,315

42,968

7.2

25,436.1

968.8

2.1

10,034.3

3,682.7

533.8

0.1

6.7

1,897.8

0.0

398.0

0.0

39,413

865,222

8,014

1.80

0.018

0.332

0.027

21.95

3,555

64,093

129

62.04

0.650

1.029

0.367

18.0

---

39,379

864,614

7,875

1.83

0.017

0.332

0.027

21.96

499

100

864,614

39,379

7.2

25,436.0

967.9

2.1

10,034.2

101.1

532.1

0.1

2.7

1,897.7

0.0

398.0

0.0

39,379

864,614

7,875

1.83

0.017

0.332

0.027

21.96

3,589

64,701

129

62.30

0.716

1.029

0.363

18.0

499

100

929,315

42,968

7.2

25,436.1

968.8

2.1

10,034.3

3,682.7

533.8

0.1

6.7

1,897.8

0.0

398.0

0.0

1,109

20,000

62.31

0.716

1.029

0.363

18.0

---

519

100

20,000

1,109

0.0

1,107.1

0.5

0.0

0.3

0.0

1.2

0.0

3,589

64,701

129

62.30

0.716

1.029

0.363

18.0

1.83

0.017

0.332

0.027

21.96

499

100

64,701

3,589

0.0

3,581.6

1.7

0.0

0.2

1.0

0.0

4.0

0.1

0.0

Material Balance SGT PRB + PETOCKE 50% H2S 16 Sep.xls Mat Bal Page 2 of 7

SYNGAS TREATING AREA

43F PRB + PETCOKE

Table 1

Component Balance

9/14/2006

Project No: 42127

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

Component lb-moles/hr

NH3

NO2

SO2

Sulfur

CH4

CO2

COS

H2O

H2S

HCN

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

308

Sour Water to

Elluent Heat

Exchange

309

Sour Gas to

Sulrur Recovery

Unit (SRU)

310

Recycle Gas from SRU

311

Sour Water from

Tail Gas Treating

(TGTU) to Sour

Water Stripper

312

Sulfur Product

313

Oxygen to SRU

314

Syngas to

Mercury Removal

315

Syngas from

Mercury Removal

316

Syngas to AGR

---

1,072

39,244

2,648

0.25

0.014

0.233

0.011

36.61

100

39,244

1,072

0.0

12.0

0.0

1.8

0.0

127.2

387.1

1.7

10.6

0.0

531.5

0.0

2,479

44,701

62.30

0.716

1.029

0.363

18.0

1.83

0.017

0.332

0.027

21.96

519

100

44,701

2,479

0.0

2,474.5

1.2

0.0

0.1

0.7

0.0

2.8

0.0

556

303

23,591

688

23,591

163

2.41

0.023

0.287

0.027

34.29

---

0.0

13.5

493.3

0.0

139.1

6.3

17.9

0.0

17.8

0.0

104

1,155

0.0

64.1

0.0

1,155

62.18

0.651

1.031

0.365

18.0

0.06

0.009

1.354

0.086

5.17

---

100

15,263

476

0.0

476.0

0.0

32.1

---

39,376

864,568

7,965

1.81

0.017

0.332

0.027

21.96

498

105

864,568

39,376

7.2

25,436.0

967.9

2.1

10,034.2

101.1

532.1

0.1

0.0

1,897.7

0.0

398.0

0.0

---

232

7,387

231

0.53

0.022

0.223

0.016

31.80

100

7,387

232

0.0

13.2

220.7

0.0

---

39,376

864,568

7,981

1.81

0.017

0.332

0.027

21.96

497

105

864,568

39,376

7.2

25,436.0

967.9

2.1

10,034.2

101.1

532.1

0.1

0.0

1,897.7

0.0

398.0

0.0

496

100

864,568

39,376

7.2

25,436.0

967.9

2.1

10,034.2

101.1

532.1

0.1

0.0

1,897.7

0.0

398.0

0.0

---

39,376

864,568

7,922

1.82

0.017

0.332

0.027

21.96

Material Balance SGT PRB + PETOCKE 50% H2S 16 Sep.xls Mat Bal Page 3 of 7

SYNGAS TREATING AREA

43F PRB + PETCOKE

Table 1

Component Balance

9/14/2006

Project No: 42127

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

Component lb-moles/hr

NH3

NO2

SO2

Sulfur

CH4

CO2

COS

H2O

H2S

HCN

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

400

Sweet Syngas from Selexol

401

Sweet Syngas to

Syngas

Interchanger

402

Sweet Syngas to

Coal Drying

403

Sweet Syngas to

Saturator

501

Primary Sour

Water Stripper

Feed

502

Sopur Water

Stripper

Overhead Vapor to SRU

503

Recovered Water from Sour Water

Stripper to heat exchange

504

Recovered Water from Sour Water

Stripper to Wash

Tower

505

Pump Around from SWS to Air

Cooler

62.35

0.680

1.029

0.363

18.0

37,160

800,681

7,583

1.76

0.017

0.336

0.027

21.55

490

100

800,717

37,162

7.0

24,554.2

563.4

0.4

9,724.7

98.1

0.5

0.1

0.0

1,829.6

0.0

384.4

0.0

62.35

0.680

1.029

0.363

18.0

38,302

825,287

7,816

1.76

0.017

0.336

0.027

21.55

490

100

825,324

38,304

7.2

25,308.8

580.7

0.4

10,023.6

101.1

0.5

0.1

0.0

1,885.8

0.0

396.2

0.0

---

37,162

800,717

8,750

1.53

0.019

0.333

0.030

21.55

489

181

800,717

37,162

7.0

24,554.2

563.4

0.4

9,724.7

98.1

0.5

0.1

0.0

1,829.6

0.0

384.4

0.0

62.35

0.680

1.029

0.363

18.0

1,142

24,606

233

1.76

0.017

0.336

0.027

21.55

490

100

24,607

1,142

0.0

56.2

0.0

11.8

0.0

0.2

754.6

17.3

0.0

298.9

3.0

0.0

2,479

44,701

59.56

0.301

1.044

0.392

18.0

---

498

200

44,701

2,479

0.0

2,474.5

1.2

0.0

0.1

0.7

0.0

2.8

0.0

169

296

---

296

0.11

0.013

0.336

0.017

24.70

2.9

0.2

0.0

0.8

2.3

2.7

0.3

0.0

1.8

1.1

0.0

3,315

59,727

128

58.05

0.224

1.064

0.397

18.0

---

481

253

59,727

3,315

0.0

3,315.2

0.0

0.1

0.0

3,315

59,727

124

60.20

0.343

1.040

0.388

18.0

---

480

203

59,727

3,315

0.0

3,315.2

0.0

0.1

0.0

3,315

59,727

124

60.20

0.343

1.040

0.388

18.0

---

480

179

59,727

3,315

0.0

3,315.2

0.0

0.1

0.0

Material Balance SGT PRB + PETOCKE 50% H2S 16 Sep.xls Mat Bal Page 4 of 7

SYNGAS TREATING AREA

43F PRB + PETCOKE

Table 1

Component Balance

9/14/2006

Project No: 42127

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

Component lb-moles/hr

NH3

NO2

SO2

Sulfur

CH4

CO2

COS

H2O

H2S

HCN

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

506

Pump Around from Air Cooler to

SWS

601

Saturator

Overhead Vapor

602

Syngas to Gas

Turbines

603

Saturator

Bottoms Liquid

604

Saturator

Bottoms Pump

Discharge

605

Saturator Liquid

Purge to Wash

Tower

606

Saturetor Bottms

Circulation after

Purge

607

Saturator

Circulation Liquid after Make-up

608

Saturator

Circulation Liquid after Saturator

Heater

3,315

59,727

124

60.20

0.343

1.040

0.388

18.0

---

480

179

59,727

3,315

0.0

3,315.2

0.0

0.1

0.0

480

303

930,842

44,386

7.0

24,554.2

44,386

930,842

12,479

1.24

0.020

0.360

0.032

20.97

---

563.4

0.4

9,724.7

7,321.3

0.5

0.1

0.0

1,829.6

0.0

384.4

0.0

479

405

930,842

44,386

7.0

24,554.2

563.4

0.4

9,724.7

7,321.3

0.5

0.1

0.0

1,829.6

0.0

384.4

0.0

44,386

930,842

14,286

1.09

0.022

0.359

0.035

20.97

---

481

215

1,117,687

62,033

3.5

62,016.0

0.0

0.1

0.0

8.0

4.7

0.0

---

62,033

1,117,687

2,355

59.16

0.274

1.049

0.394

18.0

0.0

0.8

0.0

516

215

1,117,687

62,033

---

62,033

1,117,687

2,355

59.17

0.274

1.049

0.394

18.0

0.0

8.0

4.7

0.0

3.5

62,016.0

0.0

0.1

0.0

0.8

0.0

300

5,405

59.17

0.274

1.049

0.394

18.0

---

516

215

5,405

300

0.0

299.9

0.0

516

215

1,112,282

61,733

3.5

61,716.0

0.0

0.1

0.0

8.0

4.7

0.0

0.8

0.0

500

209

1,246,677

69,193

3.5

69,176.2

0.0

0.1

0.0

8.0

4.7

0.0

0.8

0.0

490

335

1,246,677

69,193

3.5

69,176.2

0.0

0.1

0.0

8.0

4.7

0.0

0.8

0.0

---

61,733

1,112,282

2,344

59.17

0.274

1.049

0.394

18.0

---

69,193

1,246,677

2,619

59.34

0.284

1.047

0.393

18.0

69,193

1,246,677

2,804

55.43

0.160

1.111

0.394

18.0

---

Material Balance SGT PRB + PETOCKE 50% H2S 16 Sep.xls Mat Bal Page 5 of 7

SYNGAS TREATING AREA

43F PRB + PETCOKE

Table 1

Component Balance

9/14/2006

Project No: 42127

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

Component lb-moles/hr

NH3

NO2

SO2

Sulfur

CH4

CO2

COS

H2O

H2S

HCN

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

610

Demin Water

Make-up to

Saturator (after heat exchange)

611

Demin Water

Make-up to

Saturator (before heat exchange)

701

Flashed Vapor from Wash

Tower Bottoms

Flash

702

Flashed Liquid from Wash

Tower Bottoms

Flash

703

Recovered Wash

Water from Flash

704

Cooled

Recovered Water from Flash

705

Recovered Wash

Water from Flash after Air Cooler

706

Vapors to Jet

Ejector

707

Steam to Jet

Ejector

500

158

134,395

7,460

134,395

276

60.79

0.400

1.036

0.383

18.0

---

0.0

7,460.1

0.0

500

100

134,395

7,460

134,395

269

62.35

0.680

1.030

0.363

18.0

---

0.0

7,460.1

0.0

177

14,128

782

---

782

14,128

12,649

0.02

0.009

0.450

0.013

18.07

0.2

0.1

0.0

0.8

776.7

1.5

0.3

0.0

1.7

0.4

0.0

177

132,603

7,361

0.02

0.009

0.450

0.013

18.07

7,361

132,603

275

60.19

0.350

1.041

0.387

18.0

0.0

7,360.5

0.0

0.1

0.0

177

132,603

7,361

132,603

275

60.20

0.349

1.041

0.387

18.0

---

0.0

7,360.5

0.0

0.1

0.0

118

132,603

7,361

132,603

267

61.81

0.565

1.032

0.370

18.0

---

0.0

7,360.5

0.0

0.1

0.0

772

13,904

60.91

0.426

1.036

0.381

18.0

224

158

0.02

0.011

0.355

0.016

22.29

150

14,128

782

0.2

0.1

0.0

0.8

776.7

1.5

0.3

0.0

1.7

0.4

0.0

150

224

158

0.02

0.011

0.355

0.016

22.29

---

0.0

1.7

0.4

0.0

0.8

5.4

1.5

0.1

0.0

0.1

0.0

615

491

500

0.0

27.8

0.0

---

500

1.29

0.018

0.580

0.029

18.02

Material Balance SGT PRB + PETOCKE 50% H2S 16 Sep.xls Mat Bal Page 6 of 7

SYNGAS TREATING AREA

43F PRB + PETCOKE

Table 1

Component Balance

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

Component lb-moles/hr

NH3

NO2

SO2

Sulfur

CH4

CO2

COS

H2O

H2S

HCN

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

708

Jet Ejector

Effluent Vapor to

SWS

709

Condensate

Recovered from

Vacuum Flash

710

Recovered

Condensate to

SWS

711

Solids from

Candle Filers

Recovered in

Wash Tower

712

Recovered Wash

Water to

Disposal

327

724

---

724

770

0.02

0.012

0.431

0.018

19.15

0.0

0.1

0.0

0.8

33.2

1.5

0.1

0.0

1.7

0.4

0.0

772

13,904

60.91

0.426

1.036

0.381

18.0

0.02

0.011

0.355

0.016

22.29

150

13,904

772

0.2

0.0

771.3

0.0

0.1

0.0

772

13,904

60.92

0.426

1.036

0.381

18.0

---

150

13,904

772

0.2

0.0

771.3

0.0

0.1

0.0

Approximately

110 lb/day of solids will be removed by the filters and sent to the coal pile.

7,361

132,603

267

61.81

0.565

1.032

0.370

18.0

---

118

132,603

7,361

0.0

7,360.5

0.0

0.1

0.0

Material Balance SGT PRB + PETOCKE 50% H2S 16 Sep.xls Mat Bal Page 7 of 7

9/14/2006

Project No: 42127

SYNGAS TREATING AREA

43F PRB CO2 CAPTURE CASE

Table 1

Component Balance

9/15/2006

Project No: 42127

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

HCN

NH3

NO2

SO2

Sulfur

Component lb-moles/hr

CH4

CO2

COS

H2O

H2S

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

100

Total Makeup

Demineralized

Water

101

Raw Syngas

102

Demin Water to

Wash Tower

103

Water to Wash

Tower

104

Wash Tower

Bottoms Stream

105

Wash Tower

Overhead Vapor

106

Preheated Wash

Tower Overhead

Vapor

201

IP Steam to Sour

Gas Shift

202

Sour Gas Shift

Feed to

Interchangers

HTX-101

203

Sour Gas Shift

Feed to

Preheater HTX-

120

---

100

246,266

13,670

0.0

13,670.0

0.0

540

450

901,381

42,540

8.3

25,486.7

1,133.3

5.5

11,393.3

1,757.7

71.5

2.0

1.9

2,267.1

0.0

412.3

0.0

42,540

901,381

12,940

1.16

0.023

0.347

0.039

21.19

13,670

246,266

493

62.30

0.684

1.031

0.363

18.0

---

530

100

104,848

5,820

0.0

5,820.0

0.0

---

139

204,243

11,337

0.1

11,337.1

0.0

0.1

0.0

---

531

281

172,687

9,583

1.2

9,577.9

0.3

0.1

0.0

2.1

1.2

0.0

0.4

0.2

0.0

530

261

932,937

44,293

8.3

25,484.5

1,132.2

5.5

11,392.2

3,516.9

71.2

1.9

1.6

2,266.9

0.0

412.3

0.0

44,293

932,937

10,740

1.45

0.020

0.352

0.033

21.06

529

359

932,937

44,293

8.3

25,484.5

1,132.2

5.5

11,392.2

3,516.9

71.2

1.9

1.6

2,266.9

0.0

412.3

0.0

44,293

932,937

12,298

1.26

0.021

0.351

0.036

21.06

599

488

450,378

25,000

0.0

25,000.0

0.0

529

417

1,849,109

94,586

8.3

25,496.2

1,540.8

5.5

11,437.0

53,316.8

76.5

1.9

17.7

2,272.9

0.0

412.3

0.0

528

496

1,849,109

94,586

8.3

25,496.2

1,540.8

5.5

11,437.0

53,316.8

76.5

1.9

17.7

2,272.9

0.0

412.3

0.0

25,000

450,378

5,999

1.25

0.018

0.577

0.029

18.02

94,586

1,849,109

26,333

1.17

0.018

0.442

0.030

19.55

94,586

1,849,109

29,278

1.05

0.019

0.438

0.032

19.55

5,820

104,848

210

62.35

0.680

1.030

0.363

18.0

11,337

204,243

416

61.25

0.468

1.034

0.377

18.0

9,583

172,687

376

57.19

0.198

1.076

0.397

18.0

---

Material Balance SGT PRB CO2 Capture 15 Sep TMA Mat Bal Page 1 of 9

SYNGAS TREATING AREA

43F PRB CO2 CAPTURE CASE

Table 1

Component Balance

9/15/2006

Project No: 42127

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

HCN

NH3

NO2

SO2

Sulfur

Component lb-moles/hr

CH4

CO2

COS

H2O

H2S

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

204

1st Stage Sour

Gas Shift Inlet

205

1st Stage Sour

Gas Shift Outlet

206

2nd Stage Sour

Gas Shift Inlet

207

2nd Stage Sour

Gas Shift Outlet to HTX-103

208

Shifted Syngas to Interchanger

HTX-101

209

Shifted Syngas to

Condensing

Train

301

Sour Syngas from Saturator

Heater

302

Sour Syngas from 1st Stage

Condenser

303

Sour Syngas from 2nd Stage

Condenser

304

Sour Syngas from 3rd Stage

Condenser

---

527

572

1,849,109

94,586

8.3

25,496.2

1,540.8

5.5

11,437.0

53,316.8

76.5

1.9

17.7

2,272.9

0.0

412.3

0.0

517

962

1,849,110

94,589

8.3

5,403.7

21,639.7

0.9

31,534.3

33,216.0

81.0

0.0

19.6

2,272.9

0.0

412.3

0.0

516

550

1,849,110

94,589

8.3

5,403.7

21,639.7

0.9

31,534.3

33,216.0

81.0

0.0

19.6

2,272.9

0.0

412.3

0.0

506

629

1,849,110

94,589

8.3

1,383.2

25,660.8

0.3

35,555.5

29,194.9

81.7

0.0

19.6

2,272.9

0.0

412.3

0.0

505

591

1,849,110

94,589

8.3

1,383.2

25,660.8

0.3

35,555.5

29,194.9

81.7

0.0

19.6

2,272.9

0.0

412.3

0.0

504

514

1,849,110

94,589

8.3

1,383.2

25,660.8

0.3

35,555.5

29,194.9

81.7

0.0

19.6

2,272.9

0.0

412.3

0.0

503

368

1,849,110

94,589

8.3

1,383.2

25,660.8

0.3

35,555.5

29,194.9

81.7

0.0

19.6

2,272.9

0.0

412.3

0.0

502

342

1,849,110

94,589

8.3

1,383.2

25,660.8

0.3

35,555.5

29,194.9

81.7

0.0

19.6

2,272.9

0.0

412.3

0.0

501

335

1,849,110

94,589

8.3

1,383.2

25,660.8

0.3

35,555.5

29,194.9

81.7

0.0

19.6

2,272.9

0.0

412.3

0.0

500

334

1,849,110

94,589

8.3

1,383.2

25,660.8

0.3

35,555.5

29,194.9

81.7

0.0

19.6

2,272.9

0.0

412.3

0.0

94,586

1,849,109

32,056

0.96

0.021

0.438

0.034

19.55

94,589

1,849,110

46,535

0.66

0.027

0.469

0.065

19.55

94,589

1,849,110

32,572

0.95

0.021

0.449

0.048

19.55

94,589

1,849,110

36,115

0.85

0.023

0.455

0.055

19.55

94,589

1,849,110

34,840

0.88

0.022

0.453

0.054

19.55

94,589

1,849,110

32,154

0.96

0.021

0.449

0.050

19.55

94,589

1,849,110

26,939

1.14

0.018

0.446

0.044

19.55

89,275

1,753,210

24,709

1.18

0.018

0.441

0.044

19.64

86,611

1,705,117

23,863

1.19

0.018

0.439

0.044

19.69

86,381

1,700,966

23,830

1.19

0.018

0.438

0.044

19.69

---

5,314

95,900

217

55.18

0.090

1.115

0.394

18.0

7,979

143,993

324

55.42

0.090

1.110

0.395

18.0

8,209

148,144

333

55.44

0.090

1.109

0.395

18.0

Material Balance SGT PRB CO2 Capture 15 Sep TMA Mat Bal Page 2 of 9

SYNGAS TREATING AREA

43F PRB CO2 CAPTURE CASE

Table 1

Component Balance

9/15/2006

Project No: 42127

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

HCN

NH3

NO2

SO2

Sulfur

Component lb-moles/hr

CH4

CO2

COS

H2O

H2S

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

305

Sour Syngas from 4th Stage

Condenser

306

Sour Syngas from 5th Stage

Condenser

307

Sour Syngas from 6th Stage

Condenser

308

Sour Syngas from 7th Stage

Condenser

309

Water from

Syngas Knockout

Drum

310

Sour Water

Stripper Feed

311

Syngas to

Interchanger

HTX-109

312

Syngas to

Mercury Removal

313

Syngas from

Mercury Removal

314

Syngas To Acid

Gas Removal

499

330

1,849,110

94,589

8.3

1,383.2

25,660.8

0.3

35,555.5

29,194.9

81.7

0.0

19.6

2,272.9

0.0

412.3

0.0

498

330

1,849,110

94,589

8.3

1,383.2

25,660.8

0.3

35,555.5

29,194.9

81.7

0.0

19.6

2,272.9

0.0

412.3

0.0

497

200

1,849,110

94,589

8.3

1,383.2

25,660.8

0.3

35,555.5

29,194.9

81.7

0.0

19.6

2,272.9

0.0

412.3

0.0

496

100

1,849,110

94,589

8.3

1,383.2

25,660.8

0.3

35,555.5

29,194.9

81.7

0.0

19.6

2,272.9

0.0

412.3

0.0

85,128

1,678,342

23,446

1.19

0.018

0.437

0.045

19.72

84,970

1,675,505

23,436

1.19

0.018

0.437

0.045

19.72

67,226

1,354,669

15,731

1.44

0.017

0.411

0.045

20.15

65,418

1,320,283

12,876

1.71

0.015

0.407

0.040

20.18

---

496

100

704,916

38,885

0.0

0.1

169.5

0.0

1.2

38,691.7

1.7

0.0

20.2

0.5

0.0

9,462

170,768

383

55.57

0.090

1.106

0.395

18.0

9,619

173,605

389

55.59

0.089

1.106

0.395

18.0

27,363

494,440

1,034

59.62

0.300

1.042

0.391

18.1

29,171

528,827

1,056

62.43

0.710

1.023

0.360

18.1

38,885

704,916

1,408

62.43

0.710

1.023

0.360

18.1

4,131

74,886

150

62.43

0.710

1.023

0.360

18.1

---

496

100

74,886

4,131

0.0

18.0

0.0

0.1

4,110.4

0.2

0.0

2.1

0.1

0.0

496

114

1,319,923

65,459

8.3

1,383.2

25,491.8

0.3

35,554.3

255.4

79.9

0.0

0.7

2,272.5

0.0

412.3

0.0

495

120

1,319,923

65,459

8.3

1,383.2

25,491.8

0.3

35,554.3

255.4

79.9

0.0

0.7

2,272.5

0.0

412.3

0.0

493

120

1,319,923

65,459

8.3

1,383.2

25,491.8

0.3

35,554.3

255.4

79.9

0.0

0.7

2,272.5

0.0

412.3

0.0

492

100

1,319,923

65,459

8.3

1,383.2

25,491.8

0.3

35,554.3

255.4

79.9

0.0

0.7

2,272.5

0.0

412.3

0.0

65,459

1,319,923

13,251

1.66

0.016

0.407

0.041

20.16

65,459

1,319,923

13,420

1.64

0.016

0.407

0.041

20.16

65,459

1,319,923

13,474

1.63

0.016

0.407

0.041

20.16

65,374

1,318,393

12,975

1.69

0.015

0.407

0.040

20.17

---

1,531

62.44

0.711

1.023

0.360

18.1

Material Balance SGT PRB CO2 Capture 15 Sep TMA Mat Bal Page 3 of 9

SYNGAS TREATING AREA

43F PRB CO2 CAPTURE CASE

Table 1

Component Balance

9/15/2006

Project No: 42127

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

HCN

NH3

NO2

SO2

Sulfur

Component lb-moles/hr

CH4

CO2

COS

H2O

H2S

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

315

Recycle Water

Pump Suction

316

Recycle Water to

Interchanger

HTX-012

317

Recycle Water to

1st Stage

Condenser

318

Recycle Water to

Shift Outlet

Interchanger

HTX-102

319

Recycle Water to

Steam Generator

HTX-114

320

Recycle Water to

Flash Drum

321

Flash Steam to

Sour Shift

Reactors

322

Water Flash

Drum Purge

323

Recycle TGTU

Tail Gas

400

Sweet Syngas from AGR

---

496

100

630,030

34,754

0.0

0.1

151.5

0.0

1.1

34,581.3

1.6

0.0

18.1

0.4

0.0

---

536

100

630,010

34,754

0.0

0.1

150.6

0.0

1.1

34,584.8

1.6

0.0

15.4

0.4

0.0

34,754

630,030

1,258

62.43

0.710

1.023

0.360

18.1

34,754

630,010

1,258

62.43

0.710

1.023

0.360

18.1

---

535

198

630,010

34,754

0.0

0.1

150.6

0.0

1.1

34,584.8

1.6

0.0

15.4

0.4

0.0

1,372

2.37

0.019

0.300

0.019

35.58

534

351

630,010

34,754

0.0

0.1

150.6

0.0

1.1

34,584.8

1.6

0.0

15.4

0.4

0.0

533

474

630,010

34,754

0.0

0.1

150.6

0.0

1.1

34,584.8

1.6

0.0

15.4

0.4

0.0

19,008

346,319

5,134

1.12

0.014

0.557

0.025

18.22

532

474

630,010

34,754

0.0

0.1

150.6

0.0

1.1

34,584.8

1.6

0.0

15.4

0.4

0.0

25,000

454,280

6,765

1.12

0.014

0.558

0.025

18.17

532

474

454,280

25,000

0.0

0.1

150.2

0.0

1.1

24,832.6

1.5

0.0

14.1

0.4

0.0

25,000

454,280

6,765

1.12

0.014

0.558

0.025

18.17

1.12

0.014

0.558

0.025

18.17

532

474

175,730

9,754

0.0

9,752.2

0.0

0.4

0.0

1.3

0.0

---

531

151

175,730

9,754

0.0

9,752.2

0.0

0.4

0.0

1.3

0.0

482

131

272,797

41,973

8.2

1,376.2

1,019.7

0.1

35,461.8

229.8

0.0

3,442.6

24.0

0.0

410.5

0.0

41,973

272,797

9,283

0.49

0.011

1.071

0.080

6.50

34,754

630,010

1,315

59.74

0.305

1.038

0.389

18.1

34,715

628,638

1,428

54.89

0.090

1.120

0.391

18.1

15,746

283,691

708

49.97

0.109

1.295

0.359

18.0

9,754

175,730

438

49.97

0.109

1.295

0.359

18.0

---

9,754

175,730

438

49.97

0.109

1.295

0.359

18.0

9,754

175,730

359

60.98

0.423

1.034

0.381

18.0

---

Material Balance SGT PRB CO2 Capture 15 Sep TMA Mat Bal Page 4 of 9

SYNGAS TREATING AREA

43F PRB CO2 CAPTURE CASE

Table 1

Component Balance

9/15/2006

Project No: 42127

Stream Number

Stream Description

401

Syngas to 2nd

Stage Condenser

402

Syngas to

Coal/Coke Drying

403

Syngas to

Saturator

404

AGR Acid Gas to

Sulfur Recovery

405

Recycle TGTU

Tail Gas

406

LP CO2 to

Compressor

407

MP CO2 to

Compressor

413

Compressed

CO2 to Pipeline

414

Oxygen to SRU

416

TGTU Sour

Water Purge

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

HCN

NH3

NO2

SO2

Sulfur

Component lb-moles/hr

CH4

CO2

COS

H2O

H2S

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

---

482

131

254,794

39,203

7.7

1,285.4

952.4

0.1

33,121.5

214.7

0.0

3,215.4

22.4

0.0

383.4

0.0

39,203

254,794

8,670

0.49

0.011

1.071

0.080

6.50

---

481

305

254,794

39,203

7.7

1,285.4

952.4

0.1

33,121.5

214.7

0.0

3,215.4

22.4

0.0

383.4

0.0

39,203

254,794

11,259

0.38

0.013

1.078

0.097

6.50

---

2,770

18,003

613

0.49

0.011

1.071

0.080

6.50

482

131

18,003

2,770

0.5

90.8

67.3

0.0

2,340.3

15.2

0.0

227.2

1.6

0.0

27.1

0.0

457

0.9

63.21

1.183

1.026

0.337

18.1

301

12,434

353

0.59

0.013

0.221

0.009

41.26

12,891

327

0.7

0.6

0.0

220.2

0.0

25.5

79.5

0.0

---

292

10,667

2.57

0.023

0.276

0.024

36.48

556

303

10,667

292

0.0

5.5

0.0

11.6

225.8

0.0

43.5

2.6

3.4

0.0

17.7

352,422

8,038

0.0

2.3

8,003.1

0.1

30.5

0.0

0.1

0.0

1.7

0.0

0.6

0.0

8,038

352,422

40,368

0.15

0.014

0.207

0.009

43.84

715,524

16,321

0.0

4.6

16,248.7

0.1

61.9

0.0

0.3

0.0

3.5

0.0

1.2

0.0

2000

294

1,067,947

24,359

0.1

6.9

24,251.8

0.2

92.4

0.0

0.4

0.0

5.3

0.0

1.9

0.0

16,321

715,524

19,174

0.62

0.014

0.213

0.009

43.84

24,359

1,067,947

1,329

13.39

0.028

0.340

0.022

43.84

---

100

1,602

0.0

46.6

2.5

0.0

---

1,602

0.55

0.021

0.220

0.015

32.70

104

576

1.2

62.19

0.651

1.030

0.365

18.0

---

0.0

32.0

0.0

Material Balance SGT PRB CO2 Capture 15 Sep TMA Mat Bal Page 5 of 9

SYNGAS TREATING AREA

43F PRB CO2 CAPTURE CASE

Table 1

Component Balance

9/15/2006

Project No: 42127

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

HCN

NH3

NO2

SO2

Sulfur

Component lb-moles/hr

CH4

CO2

COS

H2O

H2S

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

417

Molten Sulfur

501

Heated Sour

Water Stripper

Feed

502

Sour Water

Stripper Gas to

SRU

503

Stripper Bottoms to Feed/Effluent

Exchanger

504

Cooled Stripper

Bottoms to

Syngas Wash

Tower

505

Stripper

Pumparound to

Cooler

506

Stripper

Pumparound

Return

601

Syngas Saturator

Overhead Vapor

602

Diluted Syngas to

Combustion

Turbines

603

Saturator

Bottoms Stream

---

100

260

2,405

0.0

75.0

0.0

4,131

74,886

156

59.66

0.299

1.039

0.389

18.1

2.74

0.020

0.276

0.020

36.45

496

200

74,886

4,131

0.0

18.0

0.0

0.1

4,110.4

0.2

0.0

2.1

0.1

0.0

185

1,152

136

0.14

0.014

0.277

0.015

32.25

---

0.0

2.1

19.2

0.0

1.3

10.0

0.4

0.1

2.3

0.2

0.0

---

252

94,151

5,226

0.0

5,226.1

0.0

0.1

0.0

5,226

94,151

202

57.98

0.225

1.065

0.397

18.0

174

94,151

5,226

---

0.0

5,226.1

0.0

0.1

0.0

5,226

94,151

195

60.27

0.356

1.040

0.387

18.0

233

81,284

4,515

---

4,515

81,284

175

58.06

0.227

1.061

0.393

18.0

0.0

4,454.0

0.0

0.4

0.0

0.2

0.0

60.2

0.0

182

81,284

4,515

---

4,515

81,284

170

59.57

0.343

1.045

0.386

18.0

0.0

4,454.0

0.0

0.4

0.0

0.2

0.0

60.2

0.0

480

306

390,691

46,747

7.7

1,284.8

952.4

0.1

33,122.1

7,759.2

0.0

3,215.4

22.4

0.0

383.4

0.0

46,747

390,691

13,284

0.49

0.013

0.877

0.078

8.36

---

479

405

627,987

55,194

7.7

1,284.8

952.4

0.1

33,122.1

7,759.2

0.0

11,493.4

191.4

0.0

383.4

0.0

481

242

1,199,289

66,573

15.9

66,548.0

0.0

0.5

7.5

0.0

1.5

0.0

55,194

627,987

17,847

0.59

0.016

0.646

0.070

11.38

---

66,573

1,199,289

2,562

58.35

0.237

1.059

0.396

18.0

Material Balance SGT PRB CO2 Capture 15 Sep TMA Mat Bal Page 6 of 9

SYNGAS TREATING AREA

43F PRB CO2 CAPTURE CASE

Table 1

Component Balance

9/15/2006

Project No: 42127

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

HCN

NH3

NO2

SO2

Sulfur

Component lb-moles/hr

CH4

CO2

COS

H2O

H2S

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

604

Saturator Btms

Pump Discharge

605

Saturator Purge to Syngas Wash

Tower

606

Saturator

Recirculation

Water

607

Saturator

Recirc/Makeup to

Heater HTX-104

608

Hot Recirculation

Water to Top of

Saturator

609

Heated Saturator

Makeup Water

610

Saturator

Makeup Water to

4th Stage

Condenser

611

Saturator

Makeup Water to

HTX-012

613

Nitrogen to AGR and Syngas

Dilution

614

Nitrogen to AGR

---

540

242

1,199,289

66,573

15.9

66,548.0

0.0

0.5

7.5

0.0

1.5

0.0

66,573

1,199,289

2,562

58.36

0.237

1.059

0.396

18.0

540

242

5,404

300

0.0

0.1

299.9

0.0

540

242

1,193,885

66,273

15.8

66,248.1

0.0

0.5

7.5

0.0

1.4

0.0

529

250

1,335,304

74,123

15.8

74,098.1

0.0

0.5

7.5

0.0

1.4

0.0

528

334

1,335,304

74,123

15.8

74,098.1

0.0

0.5

7.5

0.0

1.4

0.0

---

300

5,404

58.36

0.237

1.059

0.396

18.0

---

66,273

1,193,885

2,550

58.36

0.237

1.059

0.396

18.0

---

74,123

1,335,304

2,864

58.13

0.228

1.062

0.397

18.0

---

74,123

1,335,304

3,001

55.48

0.161

1.110

0.394

18.0

528

334

1,335,304

74,123

---

15.8

74,098.1

0.0

0.5

7.5

0.0

74,123

1,335,304

3,001

55.48

0.161

1.110

0.394

18.0

0.0

1.4

0.0

530

162

141,419

7,850

---

291

0.0

7,850.0

0.0

7,850

141,419

60.69

0.389

1.036

0.384

18.0

0.0

530

100

141,419

7,850

---

283

18.0

0.0

7,850.0

0.0

7,850

141,419

62.35

0.680

1.030

0.363

0.0

500

237

271,008

9,647

2,416

1.87

0.023

0.260

0.019

28.09

---

0.0

9,454.0

192.9

0.0

9,647

271,008

0.0

---

1,200

33,711

301

1.87

0.023

0.260

0.019

28.09

500

237

33,711

1,200

0.0

1,176.0

24.0

0.0

Material Balance SGT PRB CO2 Capture 15 Sep TMA Mat Bal Page 7 of 9

SYNGAS TREATING AREA

43F PRB CO2 CAPTURE CASE

Table 1

Component Balance

9/15/2006

Project No: 42127

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

HCN

NH3

NO2

SO2

Sulfur

Component lb-moles/hr

CH4

CO2

COS

H2O

H2S

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

615

Dilution Nitrogen to 3rd Stage

Condenser

616

Hot Dilution

Nitrogen

701

Flash Vapor from

Wash Tower

Bottoms Flash

702

Flash Liquid from

Wash Tower

Bottoms Flash

703

Recovered Wash

Water from Flash

704

Cooled

Recovered Water from Flash

705

Cooled Flash

Vapor

706

Vapors to Jet

Ejector

707

Steam to Jet

Ejector

708

Jet Ejector

Effluent Vapor to

Sour Water

Stripper

500

237

237,297

8,447

---

8,447

237,297

2,115

1.87

0.023

0.260

0.019

28.09

0.0

8,278.0

168.9

0.0

499

306

237,297

8,447

---

8,447

237,297

2,337

1.69

0.024

0.260

0.020

28.09

0.0

8,278.0

168.9

0.0

177

19,341

1,071

---

1,071

19,341

17,337

0.02

0.009

0.451

0.013

18.05

1.2

1,066.0

0.3

0.1

0.0

2.1

1.2

0.0

0.3

0.2

0.0

177

153,346

8,512

153,346

318

60.19

0.349

1.041

0.387

18.0

0.02

0.009

0.451

0.013

18.05

0.0

8,511.9

0.0

0.1

0.0

177

153,346

8,512

153,346

318

60.19

0.349

1.041

0.387

18.0

---

0.0

8,511.9

0.0

0.1

0.0

120

153,346

8,512

153,346

310

61.75

0.555

1.032

0.371

18.0

---

0.0

8,511.9

0.0

0.1

0.0

150

19,341

1,071

1,061

19,110

60.92

0.426

1.036

0.381

18.0

231

164

0.02

0.012

0.362

0.018

21.78

1.2

1,066.0

0.3

0.1

0.0

2.1

1.2

0.0

0.3

0.2

0.0

150

231

164

0.02

0.012

0.362

0.018

21.78

---

0.0

2.1

1.2

0.0

1.2

5.6

0.2

0.0

0.2

0.0

615

491

500

1.29

0.018

0.580

0.029

18.02

---

0.0

27.8

0.0

325

731

0.0

0.2

0.0

1.2

33.4

0.2

0.0

2.1

1.2

0.0

---

731

767

0.02

0.012

0.433

0.019

19.06

Material Balance SGT PRB CO2 Capture 15 Sep TMA Mat Bal Page 8 of 9

SYNGAS TREATING AREA

43F PRB CO2 CAPTURE CASE

Table 1

Component Balance

Stream Number

Stream Description

Overall Properties

Pressure, psia

Temperature, °F

Mass Flow, lb/hr

Mole Flow, lbmole/hr

HCN

NH3

NO2

SO2

Sulfur

Component lb-moles/hr

CH4

CO2

COS

H2O

H2S

Vapor Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, ACFM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

Liquid Phase Properties

Mole Flow, lbmole/hr

Mass Flow, lb/hr

Actual Volumetric Flow, USGPM

Density, lb/ft3

Viscosity, cP

Heat Capacity, Btu/lb-F

Thermal Conductivity, Btu/hr-ft-F

Molecular Weight

709

Vacuum Flash

Condensate

710

Vacuum Flash

Condensate to

Sour Water

Stripper

711

Particulate Solids

Removed from

Wash Tower

Bottoms

712

Recovered Wash

Water

1,061

19,110

60.92

0.426

1.036

0.381

18.0

0.02

0.012

0.362

0.018

21.78

150

19,110

1,061

0.0

1,060.4

0.0

0.1

0.0

0.3

0.0

1,061

19,110

60.93

0.426

1.036

0.381

18.0

---

150

19,110

1,061

0.0

1,060.4

0.0

0.1

0.0

0.3

0.0

Approximately

110 lb/day is removed from the Wash Tower

Bottoms stream.

---

1,061

19,110

60.93

0.426

1.036

0.381

18.0

1,061

19,110

60.93

0.426

1.036

0.381

18.0

---

150

19,110

1,061

0.0

1,060.4

0.0

0.1

0.0

0.3

0.0

Material Balance SGT PRB CO2 Capture 15 Sep TMA Mat Bal Page 9 of 9

9/15/2006

Project No: 42127

SITE LAYOUT DRAWINGS

B-1

CURRENT

FUTURE

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

KEY NOTES:

CONTROL ROOM/ADMIN. BLDG.

GAS TURBINE

HEAT RECOVERY STEAM GENERATOR

STEAM TURBINE

COOLING TOWER

6 GASIFICATION

AIR SEPARATION PLANT

ACID GAS SEPARATION

9 GAS CLEANUP

SULFUR PRODUCTION

SLAG HANDLING

WASTE WATER TREATMENT

WATER TREATMENT

WAREHOUSE

SULFUR LOAD-OUT SIDING

ROTARY DUMPER

COAL STOCKOUT

COAL CONVEYOR

COAL PILE (60 DAYS)

20 COAL GRINDING AND DRYING

21 YARD MAINTENANCE BLDG.

22 PLANT PARKING

23 SWITCHYARD

24 CONSTRUCTION OFFICES

25 CONSTRUCTION PARKING

26 SLAG & FINES LANDFILL

27 WASTE WATER POND

28 GAS METERING STATION

29 ACCESS SPUR

30 LOOP TRACK

31 FLARE

32 AUXILIARY BOILER

33 TAIL GAS TREATMENT UNIT

34 WATER STORAGE POND (30 DAYS)

35 SULFUR LOADOUT

300’ 0’ 300’

SCALE IN FEET

600’

294.75’

PROPERTY LINE no.

date by ckd description date

JUNE 12, 2006 designed

R. SEDLACEK detailed

R. SEDLACEK checked

550MW (NET) 2X1 IGCC UNIT 1 OF 3

OPTION 1 - 100% PRB project

42127 drawing

SK-CS1 contract sheet file of rev.

sheets

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

CURRENT

FUTURE

KEY NOTES:

CONTROL ROOM/ADMIN. BLDG.

2 GAS TURBINE

3 HEAT RECOVERY STEAM GENERATOR

4 STEAM TURBINE

5 COOLING TOWER

6 GASIFICATION

7 AIR SEPARATION PLANT

8 ACID GAS SEPARATION

9 GAS CLEANUP

SULFUR PRODUCTION

SLAG HANDLING

WASTE WATER TREATMENT 12

WATER TREATMENT

WAREHOUSE

SULFUR LOAD-OUT SIDING

ROTARY DUMPER 16

COAL STOCKOUT

COAL CONVEYORS

COAL PILE (60 DAYS)

20 COAL GRINDING AND DRYING

21 YARD MAINTENANCE BLDG.

22 PLANT PARKING

23 SWITCHYARD

24 CONSTRUCTION OFFICES

25 CONSTRUCTION PARKING

26 SLAG & FINES LANDFILL

27 WASTE WATER POND

28 GAS METERING STATION

29 ACCESS SPUR

30 LOOP TRACK

31 FLARE

32 AUXILIARY BOILER

33 TAIL GAS TREATMENT UNIT

34 WATER STORAGE POND (30 DAYS)

35 SULFUR LOADOUT

36 PET COKE PILE (30 DAYS)

300’ 0’ 300’

SCALE IN FEET

600’

294.75’

PROPERTY LINE no.

date by ckd description date

JUNE 12, 2006 designed

R. SEDLACEK detailed

R. SEDLACEK checked

550MW (NET) 2X1 IGCC UNIT 1 OF 3

OPTION 2 - 50% PRB/50% PET COKE project

42127 drawing

SK-CS2 contract sheet file of rev.

sheets

WATER MASS BALANCE DIAGRAMS

C-1

no. | date | by | chd | description

A | 6/23/06 | mab | |

B | 6/29/06 | mab | bdh |

Initial Issue

Revise Raw H

Raw Water

Influent

4,391

(2,194,622)

Potable

Water

Treatment

On-site Septic

System

(1,499)

Cartridge

Filtration

(4,498)

4,379

(2,188,624)

(44,982)

Service

Water

Storage

(7,997)

Coal

Storage

Area

(7,997)

4,289

(2,143,642)

3,597

(1,797,781)

(36,985)

Sour Water

Condensate Recycle

(26,989)

(9,996)

Slag Quench

(Non-recoverable)

Syngas

Treatment

692

(345,862)

Demineralizer

System

(RO/EDI)

Non-recoverable

Losses

199

(99,460)

(3,998)

(21,991)

234

(116,953)

Demineralized

Water

Storage

493

(246,401)

(18,992)

Oil/Water

Separator

Syngas Saturation

(Non-Recoverable)

188

(93,962)

(16,493)

(3,499)

(9,996)

Syngas Burner

(Non-Recoverable)

Non-recoverable

Losses

278

(138,944)

3,796

(1,897,241)

Gasifier Units

Condenser

HRSG Units

(9,996)

(8,996)

(5,998)

(5,498)

Process

Wastewater

Storage

3,808

(1,903,238)

4,097

(2,047,681)

Evaporation &

Drift

Cooling

Tower

3,135

(1,566,873)

NOTES:

1. FLOWS ARE SHOWN IN GALLONS PER MIN

ROUNDED TO THE NEAREST GALLON.

2. FLOWS ARE BASED ON AVERAGE DAILY

CONDITIONS.

3. FLOWS IN PARENTHESIS SHOWN IN POUNDS

PER HOUR ROUNDED TO THE NEAREST

POUND.

(17,993)

962

(480,808)

X date

6/29/2006 designed

M. Boyd detailed

M. Boyd checked

B. Hansen

998

(498,800)

1,007

(503,299)

Wastewater

Discharge to

Outfall

PRELIMINARY

550 MW (net) IGCC

Gulf Coast, Texas

Water Balance Diagram

100% PRB @ 43 F Ambient Dry

Bulb Temp. & 40 F Ambient Wet Bulb Temp.

project

42127 drawing

WMB-1.1

contract

---

rev.

B sheet file

1 of 2 sheets

42127 CPS IGCC WMB Rev B.xls

no. | date | by | chd | description

A | 6/23/06 | mab | |

B | 6/29/06 | mab | bdh |

Initial Issue

Revise Raw H

Raw Water

Influent

4,983

(2,490,503)

Potable

Water

Treatment

On-site Septic

System

(1,499)

Cartridge

Filtration

(5,498)

4,969

(2,483,506)

(44,982)

Service

Water

Storage

(7,997)

Coal

Storage

Area

(7,997)

4,879

(2,438,524)

4,208

(2,103,158)

(36,985)

Sour Water

Condensate Recycle

(26,989)

(9,996)

Slag Quench

(Non-recoverable)

Syngas

Treatment

671

(335,366)

Demineralizer

System

(RO/EDI)

Non-recoverable

Losses

193

(96,461)

(3,499)

(21,991)

234

(116,953)

Demineralized

Water

Storage

478

(238,904)

(17,993)

Oil/Water

Separator

Syngas Saturation

(Non-Recoverable)

177

(88,465)

(15,494)

(3,499)

(9,996)

Syngas Burner

(Non-Recoverable)

Non-recoverable

Losses

278

(138,944)

4,401

(2,199,620)

Gasifier Units

Condenser

HRSG Units

(8,996)

(5,498)

Process

Wastewater

Storage

4,412

(2,205,118)

4,701

(2,349,560)

Evaporation &

Drift

Cooling

Tower

3,595

(1,796,781)

NOTES:

1. FLOWS ARE SHOWN IN GALLONS PER MIN

ROUNDED TO THE NEAREST GALLON.

2. FLOWS ARE BASED ON AVERAGE DAILY

CONDITIONS.

3. FLOWS IN PARENTHESIS SHOWN IN POUNDS

PER HOUR ROUNDED TO THE NEAREST

POUND.

(17,993)

1,106

(552,779)

X date

6/29/2006 designed

M. Boyd detailed

M. Boyd checked

B. Hansen

1,142

(570,772)

1,153

(576,269)

Wastewater

Discharge to

Outfall

PRELIMINARY

550 MW (net) IGCC

Gulf Coast, Texas

Water Balance Diagram

100 % PRB @ 73 F Ambient Dry

Bulb Temp. & 69 F Ambient Wet Bulb Temp.

project

42127 drawing

WMB-1.2

contract

---

rev.

B sheet file

1 of 2 sheets

42127 CPS IGCC WMB Rev B.xls

no. | date | by | chd | description

A | 6/23/06 | mab | |

B | 6/29/06 | mab | bdh |

Initial Issue

Revise Raw H

Raw Water

Influent

5,580

(2,788,884)

Potable

Water

Treatment

On-site Septic

System

(1,499)

Cartridge

Filtration

(5,998)

5,565

(2,781,387)

(44,982)

Service

Water

Storage

(7,997)

Coal

Storage

Area

(7,997)

5,475

(2,736,405)

4,814

(2,406,037)

(36,985)

Sour Water

Condensate Recycle

(26,989)

(9,996)

Slag Quench

(Non-recoverable)

Syngas

Treatment

661

(330,368)

Demineralizer

System

(RO/EDI)

Non-recoverable

Losses

190

(94,962)

(3,499)

(21,991)

234

(116,953)

Demineralized

Water

Storage

471

(235,406)

(17,993)

Oil/Water

Separator

Syngas Saturation

(Non-Recoverable)

171

(85,466)

(14,994)

(3,499)

(9,996)

Syngas Burner

(Non-Recoverable)

Non-recoverable

Losses

278

(138,944)

5,004

(2,500,999)

Gasifier Units

Condenser

HRSG Units

(8,996)

(5,498)

Process

Wastewater

Storage

5,015

(2,506,497)

5,304

(2,650,939)

Evaporation &

Drift

Cooling

Tower

4,055

(2,026,689)

NOTES:

1. FLOWS ARE SHOWN IN GALLONS PER MIN

ROUNDED TO THE NEAREST GALLON.

2. FLOWS ARE BASED ON AVERAGE DAILY

CONDITIONS.

3. FLOWS IN PARENTHESIS SHOWN IN POUNDS

PER HOUR ROUNDED TO THE NEAREST

POUND.

(17,993)

1,249

(624,250)

X date

6/29/2006 designed

M. Boyd detailed

M. Boyd checked

B. Hansen

1,285

(642,243)

1,297

(648,241)

Wastewater

Discharge to

Outfall

PRELIMINARY

550 MW (net) IGCC

Gulf Coast, Texas

Water Balance Diagram

100% PRB @ 93 Ambient Dry

Bulb Temp. & 77 F Ambient Wet Bulb Temp.

project

42127 drawing

WMB-1.3

contract

---

rev.

B sheet file

1 of 2 sheets

42127 CPS IGCC WMB Rev B.xls

no. | date | by | chd | description

A | 6/23/06 | mab | |

B | 6/29/06 | mab | bdh |

Initial Issue

Revise Raw H

Raw Water

Influent

4,619

(2,308,576)

Potable

Water

Treatment

On-site Septic

System

(1,499)

Cartridge

Filtration

(4,998)

4,606

(2,302,079)

(44,982)

Service

Water

Storage

(7,997)

Coal

Storage

Area

(7,997)

4,516

(2,257,097)

3,689

(1,843,762)

(36,985)

Sour Water

Condensate Recycle

(26,989)

(9,996)

Slag Quench

(Non-recoverable)

Syngas

Treatment

827

(413,335)

Demineralizer

System

(RO/EDI)

Non-recoverable

Losses

238

(118,952)

(3,998)

(21,991)

234

(116,953)

Demineralized

Water

Storage

589

(294,382)

(18,992)

Oil/Water

Separator

Syngas Saturation

(Non-Recoverable)

231

(115,454)

(42,983)

(3,499)

(9,996)

Syngas Burner

(Non-Recoverable)

Non-recoverable

Losses

278

(138,944)

3,927

(1,962,715)

Gasifier Units

Condenser

HRSG Units

(9,996)

(8,996)

(5,998)

(5,498)

Process

Wastewater

Storage

3,939

(1,968,712)

4,228

(2,113,154)

Evaporation &

Drift

Cooling

Tower

3,235

(1,616,853)

NOTES:

1. FLOWS ARE SHOWN IN GALLONS PER MIN

ROUNDED TO THE NEAREST GALLON.

2. FLOWS ARE BASED ON AVERAGE DAILY

CONDITIONS.

3. FLOWS IN PARENTHESIS SHOWN IN POUNDS

PER HOUR ROUNDED TO THE NEAREST

POUND.

(17,993)

993

(496,301)

X date

6/29/2006 designed

M. Boyd detailed

M. Boyd checked

B. Hansen

1,029

(514,294)

1,039

(519,292)

Wastewater

Discharge to

Outfall

PRELIMINARY

550 MW (net) IGCC

Gulf Coast, Texas

Water Balance Diagram

50% PRB / 50% Pet Coke @ 43 F Ambient Dry

Bulb Temp. & 40F Ambient Wet Bulb Temp.

project

42127 drawing

WMB-2.1

contract

---

rev.

B sheet file

1 of 2 sheets

42127 CPS IGCC WMB Rev B.xls

no. | date | by | chd | description

A | 6/23/06 | mab | |

B | 6/29/06 | mab | bdh |

Initial Issue

Revise Raw H

Raw Water

Influent

5,231

(2,614,454)

Potable

Water

Treatment

On-site Septic

System

(1,499)

Cartridge

Filtration

(5,498)

5,217

(2,607,457)

(44,982)

Service

Water

Storage

(7,997)

Coal

Storage

Area

(7,997)

5,127

(2,562,475)

4,328

(2,163,134)

(36,985)

Sour Water

Condensate Recycle

(26,989)

(9,996)

Slag Quench

(Non-recoverable)

Syngas

Treatment

799

(399,340)

Demineralizer

System

(RO/EDI)

Non-recoverable

Losses

230

(114,954)

(3,998)

(21,991)

234

(116,953)

Demineralized

Water

Storage

569

(284,386)

(18,493)

Oil/Water

Separator

Syngas Saturation

(Non-Recoverable)

217

(108,457)

(40,484)

(3,499)

(9,996)

Syngas Burner

(Non-Recoverable)

Non-recoverable

Losses

278

(138,944)

4,558

(2,278,088)

Gasifier Units

Condenser

HRSG Units

(9,496)

(8,996)

(5,498)

Process

Wastewater

Storage

4,569

(2,283,586)

4,858

(2,428,028)

Evaporation &

Drift

Cooling

Tower

3,715

(1,856,757)

NOTES:

1. FLOWS ARE SHOWN IN GALLONS PER MIN

ROUNDED TO THE NEAREST GALLON.

2. FLOWS ARE BASED ON AVERAGE DAILY

CONDITIONS.

3. FLOWS IN PARENTHESIS SHOWN IN POUNDS

PER HOUR ROUNDED TO THE NEAREST

POUND.

(17,993)

1,143

(571,271)

X date

6/29/2006 designed

M. Boyd detailed

M. Boyd checked

B. Hansen

1,179

(589,264)

1,190

(594,762)

Wastewater

Discharge to

Outfall

PRELIMINARY

550 MW (net) IGCC

Gulf Coast, Texas

Water Balance Diagram

50% PRB / 50% Pet Coke @ 73 F Ambient Dry

Bulb Temp. & 69 F Ambient Wet Bulb Temp.

project

42127 drawing

WMB-2.2

contract

---

rev.

B sheet file

1 of 2 sheets

42127 CPS IGCC WMB Rev B.xls

no. | date | by | chd | description

A | 6/23/06 | mab | |

B | 6/29/06 | mab | bdh |

Initial Issue

Revise Raw H

Raw Water

Influent

5,800

(2,898,840)

Potable

Water

Treatment

On-site Septic

System

(1,499)

Cartridge

Filtration

(5,998)

5,785

(2,891,343)

(44,982)

Service

Water

Storage

(7,997)

Coal

Storage

Area

(7,997)

5,695

(2,846,361)

4,910

(2,454,018)

(36,985)

Sour Water

Condensate Recycle

(26,989)

(9,996)

Slag Quench

(Non-recoverable)

Syngas

Treatment

785

(392,343)

Demineralizer

System

(RO/EDI)

Non-recoverable

Losses

226

(112,955)

(3,499)

(21,991)

234

(116,953)

Demineralized

Water

Storage

559

(279,388)

(17,993)

Oil/Water

Separator

Syngas Saturation

(Non-Recoverable)

211

(105,458)

(38,984)

(3,499)

(9,996)

Syngas Burner

(Non-Recoverable)

Non-recoverable

Losses

278

(138,944)

5,136

(2,566,973)

Gasifier Units

Condenser

HRSG Units

(8,996)

(5,498)

Process

Wastewater

Storage

5,147

(2,572,471)

5,436

(2,716,913)

Evaporation &

Drift

Cooling

Tower

4,155

(2,076,669)

NOTES:

1. FLOWS ARE SHOWN IN GALLONS PER MIN

ROUNDED TO THE NEAREST GALLON.

2. FLOWS ARE BASED ON AVERAGE DAILY

CONDITIONS.

3. FLOWS IN PARENTHESIS SHOWN IN POUNDS

PER HOUR ROUNDED TO THE NEAREST

POUND.

(17,993)

1,281

(640,244)

X date

6/29/2006 designed

M. Boyd detailed

M. Boyd checked

B. Hansen

1,317

(658,237)

1,329

(664,234)

Wastewater

Discharge to

Outfall

PRELIMINARY

550 MW (net) IGCC

Gulf Coast, Texas

Water Balance Diagram

50% PRB / 50% Pet Coke @ 93 F Ambient Dry

Bulb Temp. & 77 F Ambient Wet Bulb Temp.

project

42127 drawing

WMB-2.3

contract

---

rev.

B sheet file

1 of 2 sheets

42127 CPS IGCC WMB Rev B.xls

Flow Path

A Water Supply

Filter Reject to Outfall

Service Water

Flow Description

Service Water for Coal Storage

Service Water to Slag Quench

Demin. Reject

Demin Storage Influent

Condenser Influent

HRSG Blowdown

CT Evaporation & Drift

Wastewater w/ Filter Reject to Outfall

Demin Water to Syngas Scrubber

Syngas Scrubber Effluent

Demin Water for Syngas Saturation

Gasifier Blowdown

Water for Syngas Burner

Combined CT Make-up

Raw Water Influent to Potable Water Treatment

Effluent to on-site Septic System

PRB

73°F

Flowrate

(GPM)

3595

1153

234

278

193

478

4983

177

4701

43°F

Flowrate

(GPM)

3135

1007

234

278

199

493

4391

188

4097

93°F

Flowrate

(GPM)

4055

1297

234

278

190

471

5580

171

5304

50-50 PRB-Petcoke

43°F

Flowrate

(GPM)

73°F

Flowrate

(GPM)

93°F

Flowrate

(GPM)

3235

1039

234

278

238

589

4619

231

4228

3715

1190

234

278

230

569

5231

217

4858

4155

1329

234

278

226

559

5800

211

5436

ELECTRICAL ONE-LINE DIAGRAMS

D-1

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

LINE #2 LINE #1 no.

date by

08/04/06 RDM ckd

description

ISSUED FOR

APPROVAL

192/256/320MVA

345-22kV

153/204/255MVA

345-22kV

153/204/255MVA

345-22kV

STG

320MVA

22KV

CTG 2

255MVA

22KV

45/60/75

22-13.8KV

CTG 1

255MVA

22KV

45/60/75

22-13.8KV

120MVA

345-13.8kV

120MVA

345-13.8kV

60MVA

345-13.8kV

40,000

MAC

COMPR. 1

12,000 40,000

BAC

COMPR. 1

NITROGEN

AIR

COMPR. 1

60MVA

345-13.8kV

2000/2666KVA

13,800-480V

40,000

MAC

COMPR. 2

12,000 40,000

BAC

COMPR. 2

NITROGEN

AIR

COMPR. 2

2000/2666KVA

13,800-480V

15/20MVA

13,800-4160V

2000/2666KVA

13,800-480V

15/20MVA

13,800-4160V

15/20MVA

13,800-4160V

15/20MVA

13,800-4160V

EE004

TO SULFUR &

SLAG SWGR

EE013

TO BOP

SWGR

EE002

EE003

TO GASIFICATION

SWGR

TO COAL

HANDLING SWGR

EE006

TO POWER

BLOCK SWGR B

EE005

TO POWER

BLOCK SWGR A

15/20MVA

13,800-4160V

15/20MVA

13,800-4160V

15/20MVA

13,800-4160V

2000/2666KVA

13,800-480V

15/20MVA

13,800-4160V

EE005

TO POWER

BLOCK SWGR A

EE006

TO POWER

BLOCK SWGR B

EE003

TO COAL

HANDLING SWGR

EE002

TO GASIFICATION

SWGR

EE013

TO BOP

SWGR

EE004

TO SULFUR &

SLAG SWGR date

JUNE 28, 2006 designed

R. MAHALEY detailed

V. VERMILLION checked

EPRI / CPS IGCC STUDY

OVERALL

ONE-LINE DIAGRAM contract project drawing

42127

EE001 sheet of file

42127EE001.DGN

rev.

A sheets

M:\EPRI-CPS\42127\CAD\ELEC\ONE-LINES\42127EE001.DGN 8-03-2006 15:23 V_VERMIL

1 2 3 4 5

EE001

6 7 8 9

13,800 GASIFICATION SWGR

10 11

EE001

12 13 14 15 16 17

1250

13.8KV

GASIFICATION

LOADS A

2000/2666KVA

13,800-480V

480V

GASIFICATION MCCs

1250

13.8KV

GASIFICATION

LOADS B

2000/2666KVA

13,800-480V

480V

GASIFICATION MCCs no.

date by

08/04/06 RDM ckd

description

ISSUED FOR

APPROVAL

F date

JUNE 28, 2006 designed

R. MAHALEY detailed

V. VERMILLION checked

EPRI / CPS IGCC STUDY

GASIFICATION

13.8KV SWGR project drawing

42127

EE002 sheet of file

42127EE002.DGN

contract

rev.

A sheets

M:\EPRI-CPS\42127\CAD\ELEC\ONE-LINES\42127EE002.DGN 8-03-2006 15:25 V_VERMIL

1 2 3 4 5

EE001

6 7 8 9 10 11 12 13

EE001

14 15 16 17

4160V COAL HANDLING SWGR

2000

GRINDING

MILL 1

2000/2666KVA

4160-480V

250

RECLAIM

CONV.

250

STOCKOUT

CONV.

EE009

COAL HANDLING

& GRINDING

MCC A

480V COAL HANDLING SWGR

2000/2666KVA

4160-480V

2000

GRINDING

MILL 2

150

RECLAIM DUST

COLLECTION

200

UNLDG.

CONV.

150

TRANSFER

CONVEYOR

OTHER COAL

HANDLING & GRINDING no.

date by

08/04/06 RDM ckd

description

ISSUED FOR

APPROVAL

F date

JUNE 28, 2006 designed

R. MAHALEY detailed

V. VERMILLION checked

EPRI / CPS IGCC STUDY

COAL HANDLING

4160V SWGR project drawing

42127

EE003 sheet of file

42127EE003.DGN

contract

rev.

A sheets

M:\EPRI-CPS\42127\CAD\ELEC\ONE-LINES\42127EE003.DGN 8-03-2006 15:30 V_VERMIL

1 2 3 4 5 6

EE001

7 8 9 10 11 12 13 14

EE001

15 16 17

4160V SULFUR & SLAG SWGR

2000/2666KVA

4160-480V

4160V

SULFUR & SLAG

LOADS 1A

TO SLAG & SULFUR

480V MCCs

2000/2666KVA

4160-480V

4160V

SULFUR & SLAG

LOADS 1B

TO SLAG & SULFUR

480V MCCs no.

date by

08/04/06 RDM ckd

description

ISSUED FOR

APPROVAL

F date

JUNE 28, 2006 designed

R. MAHALEY detailed

V. VEMILLION checked

EPRI / CPS IGCC STUDY

SULFUR & SLAG

4160V SWGR project drawing

42127

EE004 sheet of file

42127EE004.DGN

contract

rev.

A sheets

M:\EPRI-CPS\42127\CAD\ELEC\ONE-LINES\42127EE004.DGN 8-03-2006 15:37 V_VERMIL

1 2

EE001

3 4 5 6 7 8 9 10 11 12 13 14 15 16

EE001

4160V POWER BLOCK SWGR. A

2500

CIRC.

WATER

PUMP

CTG 1

STATION SERVICE

TRANSF. 1A

2000/2666KVA

4160-480V

350

WELL

PP1A

750

CTG 1

ATOMIZING

AIR

2500

HP/IP

FEEDWATER

PUMP 2A

2500

HP/IP

FEEDWATER

PUMP 1A

1000

AUX. COOLING

WATER PUMP 1A

PWR BLK

MCC

CTG 2

MCC

CTG 1

MCC

200

CTG 1

WATER

INJ PP

480V POWER BLOCK SWGR. A

CTG 1

MCC

EMERGENCY

MCCs

CTG 2

MCC

STG

MCC

2500

HP/IP

FEEDWATER

PUMP 1B

2500

HP/IP

FEEDWATER

PUMP 2B

750

CTG 2

ATOMIZING

AIR

350

WELL

PP1B

500

CONDENSATE

PUMP

1000

AUX. COOLING

WATER PUMP 1B

EMERGENCY

GENERATOR

CTG 2

STATION SERVICE

TRANSF. 2A

2000/2666KVA

4160-480V

CTG 1

MCC

CTG 2

MCC

200

CTG 2

WATER

INJ PP no.

date by

A 08/04/06 RDM ckd

description

ISSUED FOR

APPROVAL date

JUNE 28, 2006 designed

R. MAHALEY detailed

V. VERMILLION checked

EPRI / CPS IGCC STUDY

POWER BLOCK

SWITCHGEAR A project drawing

42127

EE005 sheet of file

42127EE005.DGN

contract

rev.

A sheets

M:\EPRI-CPS\42127\CAD\ELEC\ONE-LINES\42127EE005.DGN 8-03-2006 15:39 V_VERMIL

1 2

EE001

3 4 5 6 7 8 9 10 11 12 13 14 15 16

EE001

4160V POWER BLOCK SWGR B

COOLING

TOWER

MCC 18

CTG 1

STATION SERVICE

TRANSF. 1B

2000/2666KVA

4160-480V

1000

CLOSED

COOLING

WATER

PUMP 1A

750

CTG 1

ATOMIZING

AIR

2500

CIRCULATING

WATER

PUMP 1C

500

CONDENSATE

PUMP 1A

HRSG 1

MCC

STG 1A

MCC

480V SWGR. B

500

CONDENSATE

PUMP 1B

2500 1000

CIRCULATING

WATER

PUMP 1B

CLOSED

COOLING WATER

PUMP 1B

350

WELL

PP1C

COOLING

TOWER

MCC 28

HRSG 2

MCC

STG 1B

MCC

CTG 2

STATION SERVICE

TRANSF. 2B

2000/2666KVA

4160-480V no.

date by

08/04/06 RDM ckd

description

ISSUED FOR

APPROVAL

F date

JUNE 28, 2006 designed

R. MAHALEY detailed

V. VERMILLION checked

EPRI / CPS IGCC STUDY

POWER BLOCK

SWITCHGEAR B project drawing

42127

EE006 sheet of file

42127EE006.DGN

contract

rev.

A sheets

M:\EPRI-CPS\42127\CAD\ELEC\ONE-LINES\42127EE006.DGN 8-03-2006 15:43 V_VERMIL

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

EE001

WATER TREATMENT

MCC

CONTROL RM/

ADMIN BLDG

PNL

BOP MCC A

40A

FLARE KO DRUM PUMP

CONDENSATE TRANSFER

PUMP 1

WELL PUMP

HOUSE #1 PANEL

480-208/120V

30KVA 3 PH,

DRY TYPE

WAREHOUSE

PNL

FIRE PUMP

SKID

BOP MCC B

40A

CONDENSATE TRANSFER

PUMP 2

WELL PUMP 4

POTABLE WATER

10WWW-PMP4

WELL PUMP

HOUSE #2 PANEL

480-208/120V

30KVA 3 PH,

DRY TYPE

NOTES:

FOR GENERAL SYMBOLS AND LEGENDS, REFER TO DWG. E001.

NEMA 1 ENCLOSURE.

INCOMING MAIN POWER CABLES ARE TOP ENTRY.

no.

date by

08/04/06 RDM ckd

description

ISSUED FOR

APPROVAL

F date

JUNE 28, 2006 designed

R. MAHALEY detailed

V. VERMILLION checked

EPRI / CPS IGCC STUDY

BALANCE OF PLANT

480V SWITCHGEAR & MCC project drawing

42127

EE007 sheet of file

42127EE007.DGN

contract

rev.

A sheets

M:\EPRI-CPS\42127\CAD\ELEC\ONE-LINES\42127EE007.DGN 8-03-2006 16:04 V_VERMIL

CAPITAL COST DETAIL

E-1

Burns McDonnell

Confidential

EPRI/CPS - 2x1 7FB IGCC Cost Estimate Summary - 100% PRB

Project Desc:

Project #:

550 MW (Net) 2x1 7FB IGCC - 100% PRB

42127

Account /

Contract

Description

100

101

102

103

104

105

106

107

108

109

FLA

110

111

112

112A

113

114

115

116

117

118

127

128

129

130

131

1201

1202

121

122

123

124

125

126

PROCUREMENT

Major Equipment

Gas Turbine - Generator

Steam Turbine - Generator

Steam Generator / Heat Recovery Steam Generator

Flue Gas Desulfurization System

Particulate Removal (Baghouse or Precip)

SCR / CO Catalyst

Bypass Stack

Stack

Surface Condenser & Air Removal Equipment

Cooling Tower

Flare

Mechanical Procurement

Boiler Feed Pumps

Condensate Pumps

Circulating Water Pumps

Aux Cooling Water Pumps

Miscellaneous Pumps

Compressed Air Equipment

Deaerator

Closed Feedwater Heaters

Auxiliary Boiler

Heat Exchangers

Electrical & Control Procurement

GSU Transformers

Auxiliary Transformers

Generator Breakers

Iso Phase Bus Duct

Small (480 V & 5 kV) Power Transformers

Emergency Diesel Generator

Medium Voltage Metal-Clad Switchgear

480 V Switchgear & Transformers

480 V Motor Control Center

Electrical Control Boards

Battery & UPS System

Freeze Protection System

Relay & Metering Panels

Client:

Estimate By:

EPRI / CPS Energy

J. Schwarz

Material

Dollars Manhours

Labor

Dollars

Subcontract

Dollars

Date:

Revision:

Subcontract

Indirect $

07/20/06

Total

Dollars

86,000,000

22,950,840

28,080,000

4,138,000

3,169,814

367,500

819,052

649,251

250,000

330,000

1,896,000

18,000,000

4,160,000

1,200,000

5,390,000

7,915,000

6,905,000

620,000

1,075,000

10,133,333

6,102,434

$ 86,000,000

$ 22,950,840

$ 28,080,000

$ -

$ 4,138,000

$ 10,133,333

$ 6,102,434

$ -

$ 3,169,814

$ 367,500

$ 819,052

$ 649,251

$ 250,000

$ 330,000

$ -

$ 1,896,000

$ -

$ 18,000,000

$ 4,160,000

$ 1,200,000

$ 5,390,000

$ -

$ 7,915,000

$ 6,905,000

$ -

$ 620,000

$ -

$ 1,075,000

1 of 5 CPS 2x1 7FB IGCC - 100% PRB (working) R0.xls

Burns McDonnell

Confidential

Account /

Contract

Description

160

161

162

163

170

171

172

173

174

180

181

182

183

190

191

192

145

146

147

150

151

152

153

154

155

156

157

158

135

136

137

140

141

142

143

144

195

196

197

Distributed Control System

Continuous Emission Monitors

Instrumentation

Natural Gas Equipment Procurement

Gas Compressors

Fuel Gas Filter/Separator

Fuel Gas Dewpoint Heater

Fuel Gas Efficiency Heater

Fuel Flow Measurement / Monitoring Equipment

Material Handling

Coal Handling Equipment

Ash Handling Equipment

Limestone / Lime Handling Equipment

Water Treatment & Chemical Storage

Raw Water Treatment

RO/EDI or Demineralizer

Condensate Polisher

Chemical Feed Equipment (Boiler Cycle)

Ammonia Supply & Storage

Supply & Storage

Chemical Feed Equipment

Sample Analysis Panel

Wastewater Treatment Equipment

Misc Mechanical

Critical Pipe

Balance of Plant Pipe

Pipe Supports

Circulating Water Pipe

High Pressure Valves

Low Pressure Valves

Large Butterfly Valves (>24")

Control Valves

Steam Turbine Bypass Valves

Shop Fabricated Tanks

Oil/Water Separator

Closed Cooling Water Heat Exchanger

Piping Specials

Fire Protection

Fire Protection System

Fire Pumps

Flammable/Combustible Storage Enclosure

Structural Procurement

Bridge Crane

Structural Steel

Fixators

EPRI/CPS - 2x1 7FB IGCC Cost Estimate Summary - 100% PRB

Material

Labor

Manhours

Dollars

1,366,075

572,900

611,725

214,864

59,000

982,500

754,000

146,462

20,000

270,000

200,000

12,000

7,425,524

532,000

3,591,000

165,000

1,151,500

300,000

626,360

630,000

205,000

58,000

2,228,100

165,500

1,357,960

216,300

1,485,138

117,000

Dollars

Subcontract Subcontract

Indirect $

Dollars

31,600,000

5,000,000

Total

Dollars

$ -

$ 1,366,075

$ 572,900

$ 611,725

$ -

$ 214,864

$ -

$ 31,659,000

$ 5,000,000

$ -

$ 982,500

$ 754,000

$ -

$ 146,462

$ -

$ 20,000

$ 270,000

$ 200,000

$ 12,000

$ -

$ 7,425,524

$ -

$ 532,000

$ 3,591,000

$ 165,000

$ 1,151,500

$ 300,000

$ 626,360

$ 630,000

$ 205,000

$ 58,000

$ 2,228,100

$ 165,500

$ -

$ 1,357,960

$ 216,300

$ -

$ 1,485,138

$ 117,000

2 of 5 CPS 2x1 7FB IGCC - 100% PRB (working) R0.xls

EPRI/CPS - 2x1 7FB IGCC Cost Estimate Summary - 100% PRB

Burns McDonnell

Confidential

ASU

GAS

SGT

200

201

202

203

204

205

206

210

211

212

213

214

215

216

220

221

222

223

290

291

299

2301

2310

231

232

260

2401

2402

2403

2404

2405

2406

2407

2408

CONSTRUCTION

Material

Manhours

Labor

Dollars

Subcontract Subcontract Total

Account /

Contract

Description

Sub-EPC Packages

Air Separation Unit and N2 Storage

Dollars

Gasification -

Syngas Treatment

Major Equipment Erection

Combustion Turbine Generator Erection

Steam Turbine - Generator Erection

Steam Generator / HRSG Erection

FGD System Erection

Particulate Removal (Baghouse or Precip) Erection

SCR / CO Catalyst Erection

Chimney

Civil / Structural Construction

Site Preparation

Piling

Substructures

Underground Utilities

Yard Structures

Foundations

Railroad

Structural Steel

Power Plant Structures

Pre-engineered Buildings

Sanitary Drains / Treatment

Final Painting

Final Paving, Landscaping & Cleanup

Demolition

Mechanical Construction

Misc Mechanical Equipment Erection

Below Grade Piping

Above Grade Piping

Insulation and Lagging

Field Erected Tanks

7,488

3,154,045

4,068,872

338,331

988,000

486,405

373,650

6,475,923

760,000

Electrical Construction

Electrical Equipment Erection

Wire / Cable

Grounding

Raceway

Lighting

Heat Tracing

Instrumentation

250,000

2,223,970

57,124

Switchyard -

230,285

3,324,536

1,458,605

8,825,957

12,717,757

8,601,390

1,097,378

840,172

72,487

2,904,083

3,288,263

10,986,993

1,656,923

3,179,171

2,167,145

650,680

430,586

72,651

31,875

165,750

297,345

188,696

24,831

18,896

1,695

63,463

73,953

247,098

36,210

69,459

47,350

14,216

9,410

Dollars

Indirect $

102,400,000

354,306,139

149,993,742

17,000

500,000

40,313,746

3,301,520

189,900

10,040,500

6,783,360

1,170,000

389,928

1,071,134

1,373,690

765,000

2,260,000

10,000

10,890,000

1,773,346

778,037

4,045,792

182,817

1,549,071

1,805,122

6,031,409

773,415

1,097,335

1,405,157

281,909

156,067

Dollars

$ -

$ 102,400,000

$ 354,306,139

$ 149,993,742

$ -

$ 5,122,369

$ 2,236,642

$ 13,371,748

$ -

$ 56,185,548

$ 3,301,520

$ -

$ 12,860,162

$ 10,040,500

$ 1,435,708

$ 6,783,360

$ -

$ 3,180,990

$ 948,819

$ -

$ 4,453,154

$ 6,538,169

$ 24,868,015

$ 3,955,338

$ 2,260,000

$ -

$ 4,526,506

$ 5,796,271

$ -

$ 1,162,874

$ -

$ 653,777

$ 10,890,000

$ -

3 of 5 CPS 2x1 7FB IGCC - 100% PRB (working) R0.xls

Burns McDonnell

Confidential

Account /

Contract

Description

5000

5001

5002

5003

5004

5005

5006

5012

5007

5008

5009

5010

5011

5050

5051

5052

5053

5064

5054

5055

5056

5057

5058

5059

5060

EPC CONTRACTOR INDIRECT COSTS

Construction Indirects

Construction Management

Field Office Expense

Temporary Facilities

Temporary Utilities

Construction Equipment / Operators

Heavy Haul

Small Tools & Consumables

Labor Per Diem & Benefits

Site Services

Construction Testing

Preoperational Testing, Startup, & Calibration

Safety

Miscellaneous Construction Indirects

Project Indirects

Site Surveys/Studies

Performance Testing

Project Management & Engineering

Training

Warranty

Operating Spare Parts

Project Insurance

Project Bonds

Escalation

Sales Tax

EPC Contingency

EPC Fee

TOTAL EPC PROJECT COST

EPRI/CPS - 2x1 7FB IGCC Cost Estimate Summary - 100% PRB

Material

Labor

Subcontract Subcontract

Dollars Manhours Dollars Dollars Indirect $

146,400

40,000,000

1,530

70,011

24,714,000

2,954,590

1,331,911

500,000

8,016,000

700,000

600,000

500,000

2,961,450

57,099,042

119,907,989

Total

Dollars

$ -

$ 24,714,000

$ -

$ 2,954,590

$ -

$ 1,331,911

$ -

$ 500,000

$ 8,232,411

$ -

$ 700,000

$ 600,000

$ 40,000,000

$ 500,000

$ -

$ 2,961,450

$ -

$ 57,099,042

$ 119,907,989

278,939,856 1,364,428 62,272,136 957,896,409 19,879,477 1,318,987,878

4 of 5 CPS 2x1 7FB IGCC - 100% PRB (working) R0.xls

Burns McDonnell

Confidential

EPRI/CPS - 2x1 7FB IGCC Cost Estimate Summary - 100% PRB

6008

6009

6010

6011

6012

6013

6014

6015

6000

6001

6002

6003

6004

6005

6006

6007

6016

6017

6018

6019

6020

6021

6022

Material

Account /

Contract

Description

Owner Indirects

Project Development

Owner Personnel

Owners OE

Owners Legal Council

Owner Startup Engineering

Permitting & License Fees

Land

Water Rights

Political Concessions / Area Development Fees / Labor Camps

Startup/Testing

Initial Fuel Inventory

Site Surveys/Studies

Site Security

Transmission Interconnection / Upgrades

Operating Spare Parts

Permanent Plant Equipment & Furnishings

Builder's Risk Insurance

Escalation Owner's Indirects

Sales Tax & Duties

Owner Contingency

Financing Fees

Interest During Construction

Dollars

10,055,869

4,600,000

Manhours

Labor

Dollars

Subcontract

Dollars

3,000,000

7,200,000

23,000,000

2,000,000

2,910,000

7,500,000

1,000,000

5,186,487

10,927,224

1,728,000

5,935,445

70,201,545

Subcontract

Indirect $

Total

Dollars

$ -

$ 3,000,000

$ 7,200,000

$ 23,000,000

$ 2,000,000

$ -

$ 2,910,000

$ 7,500,000

$ -

$ 1,000,000

$ 5,186,487

$ 10,927,224

$ -

$ 1,728,000

$ -

$ 10,055,869

$ 4,600,000

$ 5,935,445

$ -

$ 70,201,545

$ -

TOTAL OWNER COST

TOTAL EPC PROJECT COST

TOTAL OWNER'S COST

PROJECT TOTAL

14,655,869 140,588,702 155,244,571

$ 278,939,856

$ 14,655,869

1,364,428

$ 62,272,136 $ 957,896,409

$ 140,588,702

$ 19,879,477 $ 1,318,987,878

$ 155,244,571

$ 293,595,725 1,364,428 $ 62,272,136 $ 1,098,485,111 $ 19,879,477 $ 1,474,232,449

5 of 5 CPS 2x1 7FB IGCC - 100% PRB (working) R0.xls

EPRI/CPS - 2x1 7FB IGCC Cost Estimate Summary - 50% PRB / 50% Pet Coke

Project Desc:

Project #:

550 MW (Net) 2x1 7FB IGCC - 50% PRB/50% Petcoke

42127

Account /

Contract

Description

100

101

102

103

104

105

106

107

108

109

FLA

110

111

112

112A

113

114

115

116

117

118

127

128

129

130

131

1201

1202

121

122

123

124

125

126

PROCUREMENT

Major Equipment

Gas Turbine - Generator

Steam Turbine - Generator

Steam Generator / Heat Recovery Steam Generator

Flue Gas Desulfurization System

Particulate Removal (Baghouse or Precip)

SCR / CO Catalyst

Bypass Stack

Stack

Surface Condenser & Air Removal Equipment

Cooling Tower

Flare

Mechanical Procurement

Boiler Feed Pumps

Condensate Pumps

Circulating Water Pumps

Aux Cooling Water Pumps

Miscellaneous Pumps

Compressed Air Equipment

Deaerator

Closed Feedwater Heaters

Auxiliary Boiler

Heat Exchangers

Electrical & Control Procurement

GSU Transformers

Auxiliary Transformers

Generator Breakers

Iso Phase Bus Duct

Small (480 V & 5 kV) Power Transformers

Emergency Diesel Generator

Medium Voltage Metal-Clad Switchgear

480 V Switchgear & Transformers

480 V Motor Control Center

Electrical Control Boards

Battery & UPS System

Freeze Protection System

Relay & Metering Panels

Client:

Estimate By:

EPRI / CPS Energy

J. Schwarz

Material

Dollars Manhours

Labor

Dollars

Subcontract

Dollars

Date:

Revision:

Subcontract

Indirect $

07/20/06

Total

Dollars

86,000,000

22,950,840

28,080,000

4,138,000

3,169,814

367,500

819,052

649,251

250,000

330,000

1,896,000

18,000,000

4,160,000

1,200,000

5,820,000

8,465,000

8,355,000

620,000

1,075,000

10,133,333

6,102,434

$ 86,000,000

$ 22,950,840

$ 28,080,000

$ -

$ 4,138,000

$ 10,133,333

$ 6,102,434

$ -

$ 3,169,814

$ 367,500

$ 819,052

$ 649,251

$ 250,000

$ 330,000

$ -

$ 1,896,000

$ -

$ 18,000,000

$ 4,160,000

$ 1,200,000

$ 5,820,000

$ -

$ 8,465,000

$ 8,355,000

$ -

$ 620,000

$ -

$ 1,075,000

Burns McDonnell

Confidential

1 of 5 CPS 2x1 7FB IGCC - 50% PRB - 50% Pet Coke (working) R0.xls

Account /

Contract

Description

160

161

162

163

170

171

172

173

174

180

181

182

183

190

191

192

145

146

147

150

151

152

153

154

155

156

157

158

135

136

137

140

141

142

143

144

195

196

197

Distributed Control System

Continuous Emission Monitors

Instrumentation

Natural Gas Equipment Procurement

Gas Compressors

Fuel Gas Filter/Separator

Fuel Gas Dewpoint Heater

Fuel Gas Efficiency Heater

Fuel Flow Measurement / Monitoring Equipment

Material Handling

Coal Handling Equipment

Ash Handling Equipment

Limestone / Lime Handling Equipment

Water Treatment & Chemical Storage

Raw Water Treatment

RO/EDI or Demineralizer

Condensate Polisher

Chemical Feed Equipment (Boiler Cycle)

Ammonia Supply & Storage

Supply & Storage

Chemical Feed Equipment

Sample Analysis Panel

Wastewater Treatment Equipment

Misc Mechanical

Critical Pipe

Balance of Plant Pipe

Pipe Supports

Circulating Water Pipe

High Pressure Valves

Low Pressure Valves

Large Butterfly Valves (>24")

Control Valves

Steam Turbine Bypass Valves

Shop Fabricated Tanks

Oil/Water Separator

Closed Cooling Water Heat Exchanger

Piping Specials

Fire Protection

Fire Protection System

Fire Pumps

Flammable/Combustible Storage Enclosure

Structural Procurement

Bridge Crane

Structural Steel

Fixators

Burns McDonnell

Confidential

EPRI/CPS - 2x1 7FB IGCC Cost Estimate Summary - 50% PRB / 50% Pet Coke

Material

Labor

Manhours

Dollars

1,391,075

572,900

662,725

214,864

118,000

982,500

754,000

146,462

20,000

270,000

200,000

12,000

7,425,524

532,000

3,591,000

165,000

1,151,500

300,000

626,360

630,000

205,000

58,000

2,228,100

165,500

1,857,960

216,300

1,485,138

117,000

Dollars

Subcontract Subcontract

Indirect $

Dollars

41,100,000

3,077,861

Total

Dollars

$ -

$ 1,391,075

$ 572,900

$ 662,725

$ -

$ 214,864

$ -

$ 41,218,000

$ 3,077,861

$ -

$ 982,500

$ 754,000

$ -

$ 146,462

$ -

$ 20,000

$ 270,000

$ 200,000

$ 12,000

$ -

$ 7,425,524

$ -

$ 532,000

$ 3,591,000

$ 165,000

$ 1,151,500

$ 300,000

$ 626,360

$ 630,000

$ 205,000

$ 58,000

$ 2,228,100

$ 165,500

$ -

$ 1,857,960

$ 216,300

$ -

$ 1,485,138

$ 117,000

2 of 5 CPS 2x1 7FB IGCC - 50% PRB - 50% Pet Coke (working) R0.xls

Account /

Contract

Description

200

201

202

203

204

205

206

210

211

212

213

214

215

216

220

221

222

223

290

291

299

ASU

GAS

SGT

2301

2310

231

232

260

2401

2402

2403

2404

2405

2406

2407

2408

CONSTRUCTION

Sub-EPC Packages

Air Separation Unit and N2 Storage

Gasification

Syngas Treatment

Major Equipment Erection

Combustion Turbine Generator Erection

Steam Turbine - Generator Erection

Steam Generator / HRSG Erection

FGD System Erection

Particulate Removal (Baghouse or Precip) Erection

SCR / CO Catalyst Erection

Chimney

Civil / Structural Construction

Site Preparation

Piling

Substructures

Underground Utilities

Yard Structures

Foundations

Railroad

Structural Steel

Power Plant Structures

Pre-engineered Buildings

Sanitary Drains / Treatment

Final Painting

Final Paving, Landscaping & Cleanup

Demolition

Mechanical Construction

Misc Mechanical Equipment Erection

Below Grade Piping

Above Grade Piping

Insulation and Lagging

Field Erected Tanks

Electrical Construction

Electrical Equipment Erection

Wire / Cable

Grounding

Raceway

Lighting

Heat Tracing

Instrumentation

Switchyard

Burns McDonnell

Confidential

EPRI/CPS - 2x1 7FB IGCC Cost Estimate Summary - 50% PRB / 50% Pet Coke

Material

Labor

Subcontract Subcontract Total

Dollars

Manhours

Dollars

7,488

3,121,355

4,417,676

338,331

988,000

486,405

373,650

6,475,923

760,000

250,000

2,223,970

230,285

57,124

3,324,536

1,458,605

8,825,957

12,678,548

9,966,627

1,097,378

840,172

72,487

2,904,083

3,288,263

10,986,993

1,656,923

3,479,360

2,167,145

650,680

464,542

72,651

31,875

165,750

296,428

218,646

24,831

18,896

1,695

63,463

73,953

247,098

36,210

76,018

47,350

14,216

10,152

Dollars

Indirect $

102,400,000

306,357,314

158,147,910

17,000

500,000

40,009,951

3,499,160

204,460

10,040,500

6,783,360

1,170,000

389,928

1,071,134

1,373,690

765,000

2,260,000

20,000

10,890,000

1,773,346

778,037

4,045,792

182,817

1,549,071

1,805,122

6,031,409

773,415

1,193,395

1,405,157

281,909

166,933

Dollars

$ -

$ 102,400,000

$ 306,357,314

$ 158,147,910

$ -

$ 5,122,369

$ 2,236,642

$ 13,371,748

$ -

$ 55,809,853

$ 3,499,160

$ -

$ 14,588,763

$ 10,040,500

$ 1,435,708

$ 6,783,360

$ -

$ 3,180,990

$ 948,819

$ -

$ 4,453,154

$ 6,538,169

$ 24,868,015

$ 3,955,338

$ 2,260,000

$ -

$ 4,922,755

$ 5,796,271

$ -

$ 1,162,874

$ -

$ 708,598

$ 10,890,000

$ -

3 of 5 CPS 2x1 7FB IGCC - 50% PRB - 50% Pet Coke (working) R0.xls

Account /

Contract

Description

5000

5001

5002

5003

5004

5005

5006

5012

5007

5008

5009

5010

5011

5050

5051

5052

5053

5064

5054

5055

5056

5057

5058

5059

5060

EPC CONTRACTOR INDIRECT COSTS

Construction Indirects

Construction Management

Field Office Expense

Temporary Facilities

Temporary Utilities

Construction Equipment / Operators

Heavy Haul

Small Tools & Consumables

Labor Per Diem & Benefits

Site Services

Construction Testing

Preoperational Testing, Startup, & Calibration

Safety

Miscellaneous Construction Indirects

Project Indirects

Site Surveys/Studies

Performance Testing

Project Management & Engineering

Training

Warranty

Operating Spare Parts

Project Insurance

Project Bonds

Escalation

Sales Tax

EPC Contingency

EPC Fee

TOTAL EPC PROJECT COST

EPRI/CPS - 2x1 7FB IGCC Cost Estimate Summary - 50% PRB / 50% Pet Coke

Material

Labor

Subcontract Subcontract

Dollars Manhours Dollars Dollars Indirect $

146,400

40,000,000

1,530

70,011

24,714,000

2,954,590

1,331,911

500,000

8,016,000

700,000

600,000

500,000

2,890,860

55,738,004

117,049,808

Total

Dollars

$ -

$ 24,714,000

$ -

$ 2,954,590

$ -

$ 1,331,911

$ -

$ 500,000

$ 8,232,411

$ -

$ 700,000

$ 600,000

$ 40,000,000

$ 500,000

$ -

$ 2,890,860

$ -

$ 55,738,004

$ 117,049,808

282,320,970 1,400,762 63,932,307 921,308,208 19,986,403 1,287,547,889

Burns McDonnell

Confidential

4 of 5 CPS 2x1 7FB IGCC - 50% PRB - 50% Pet Coke (working) R0.xls

EPRI/CPS - 2x1 7FB IGCC Cost Estimate Summary - 50% PRB / 50% Pet Coke

Account /

Contract

Description

6008

6009

6010

6011

6012

6013

6014

6015

6000

6001

6002

6003

6004

6005

6006

6007

6016

6017

6018

6019

6020

6021

6022

Owner Indirects

Project Development

Owner Personnel

Owners OE

Owners Legal Council

Owner Startup Engineering

Permitting & License Fees

Land

Water Rights

Political Concessions / Area Development Fees / Labor Camps

Startup/Testing

Initial Fuel Inventory

Site Surveys/Studies

Site Security

Transmission Interconnection / Upgrades

Operating Spare Parts

Permanent Plant Equipment & Furnishings

Builder's Risk Insurance

Escalation Owner's Indirects

Sales Tax & Duties

Owner Contingency

Financing Fees

Interest During Construction

TOTAL OWNER COST

TOTAL EPC PROJECT COST

TOTAL OWNER'S COST

PROJECT TOTAL

Material

Labor

Dollars

10,123,491

4,600,000

Manhours

Dollars

Subcontract

Dollars

3,000,000

7,200,000

23,000,000

2,000,000

2,910,000

7,500,000

1,000,000

(3,499,854)

6,191,274

1,728,000

5,793,965

67,954,738

Subcontract

Indirect $

Total

Dollars

$ -

$ 3,000,000

$ 7,200,000

$ 23,000,000

$ 2,000,000

$ -

$ 2,910,000

$ 7,500,000

$ -

$ 1,000,000

$ (3,499,854)

$ 6,191,274

$ -

$ 1,728,000

$ -

$ 10,123,491

$ 4,600,000

$ 5,793,965

$ -

$ 67,954,738

$ -

14,723,491 124,778,124 139,501,616

$ 282,320,970

$ 14,723,491

1,400,762

$ 63,932,307

$ -

$ 921,308,208

$ 124,778,124

$ 19,986,403

$ -

$ 1,287,547,889

$ 139,501,616

$ 297,044,462 1,400,762 $ 63,932,307 $ 1,046,086,333 $ 19,986,403 $ 1,427,049,505

Burns McDonnell

Confidential

5 of 5 CPS 2x1 7FB IGCC - 50% PRB - 50% Pet Coke (working) R0.xls

Burns McDonnell

Confidential

EPRI/CPS - 550 MW Supercritical PC Cost Estimate Summary - 100% PRB

Project Desc:

Project #:

550 MW (Net) Supercritical PC - 100% PRB

42127

Client:

Estimate By:

Account /

Contract

Description

Material

Dollars

EPRI / CPS Energy

J. Schwarz

Manhours

Labor

Dollars

100

101

102

103

104

105

106

107

108

109

110

111

112

113

114

115

116

117

118

127

128

129

130

131

1201

1202

121

122

123

124

125

126

PROCUREMENT

Major Equipment

Gas Turbine - Generator

Steam Turbine - Generator

Steam Generator / Heat Recovery Steam Generator

Flue Gas Desulfurization System

Particulate Removal (Baghouse or Precip)

SCR / CO Catalyst

Bypass Stack

Stack

Surface Condenser & Air Removal Equipment

Cooling Tower

Mechanical Procurement

Boiler Feed Pumps

Condensate Pumps

Circulating Water Pumps

Miscellaneous Pumps

Compressed Air Equipment

Deaerator

Closed Feedwater Heaters

Auxiliary Boiler

Heat Exchangers

Electrical & Control Procurement

GSU Transformers

Auxiliary Transformers

Generator Breakers

Iso Phase Bus Duct

Small (480 V & 5 kV) Power Transformers

Emergency Diesel Generator

Medium Voltage Metal-Clad Switchgear

480 V Switchgear & Transformers

480 V Motor Control Center

Electrical Control Boards

Battery & UPS System

Freeze Protection System

Relay & Metering Panels

Subcontract

Dollars

Date:

Revision:

Subcontract

Indirect $

07/20/06

Total

Dollars

40,043,000

182,631,579

5,800,000

3,275,768

420,000

1,300,000

800,600

990,000

362,887

2,854,904

270,000

9,450,000

3,100,000

2,035,000

6,295,000

3,965,000

1,785,000

115,836

1,105,000

405,000

10,000,000

$ -

$ 40,043,000

$ 182,631,579

$ -

$ 5,800,000

$ 10,000,000

$ -

$ 3,275,768

$ 420,000

$ 1,300,000

$ 800,600

$ 990,000

$ 362,887

$ 2,854,904

$ -

$ 270,000

$ -

$ 9,450,000

$ 3,100,000

$ -

$ 2,035,000

$ -

$ 6,295,000

$ 3,965,000

$ 1,785,000

$ 115,836

$ 1,105,000

$ -

$ 405,000

1 of 5 550MW Super PC Cost Estimate - Greenfield.xls

Burns McDonnell

Confidential

Account /

Contract

Description

135

136

137

140

141

142

143

144

160

161

162

163

170

171

172

173

174

180

181

182

183

190

191

192

195

196

197

145

146

147

150

151

152

153

154

155

156

157

158

Distributed Control System

Continuous Emission Monitors

Instrumentation

Natural Gas Equipment Procurement

Gas Compressors

Fuel Gas Filter/Separator

Fuel Gas Dewpoint Heater

Fuel Gas Efficiency Heater

Fuel Flow Measurement / Monitoring Equipment

Material Handling

Coal Handling Equipment

Ash Handling Equipment

Limestone Handling Equipment

Water Treatment & Chemical Storage

Raw Water Treatment

RO/EDI or Demineralizer

Condensate Polisher

Chemical Feed Equipment (Boiler Cycle)

Ammonia Supply & Storage

CO2 Supply & Storage

Chemical Feed Equipment (Cooling Tower)

Sample Analysis Panel

Wastewater Treatment Equipment

Misc Mechanical

Critical Pipe

Balance of Plant Pipe

Pipe Supports

Circulating Water Pipe

High Pressure Valves

Low Pressure Valves

Large Butterfly Valves (>24")

Control Valves

Steam Turbine Bypass Valves

Shop Fabricated Tanks

Oil/Water Separator

Closed Cooling Water Heat Exchanger

Piping Specials

Fire Protection

Fire Protection System

Fire Pumps

Flammable/Combustible Storage Enclosure

Structural Procurement

Bridge Crane

Structural Steel

Fixators

EPRI/CPS - 550 MW Supercritical PC Cost Estimate Summary - 100% PRB

Material

Labor

Manhours

Dollars

6,857,723

542,190

3,195,000

1,633,159

3,287,242

792,000

1,266,411

206,000

101,500

1,584,920

325,000

1,967,360

5,301,000

600,000

1,108,310

792,500

754,000

2,225,309

190,000

301,899

30,200

250,000

12,000

Dollars

Subcontract Subcontract

Indirect $

Dollars

2,500,000

32,000,000

10,630,000

3,899,000

Total

Dollars

$ -

$ 5,301,000

$ 600,000

$ 1,108,310

$ -

$ 32,000,000

$ 10,630,000

$ 3,899,000

$ -

$ 792,500

$ 754,000

$ 2,225,309

$ 190,000

$ 301,899

$ 30,200

$ -

$ 250,000

$ 12,000

$ -

$ 6,857,723

$ -

$ 542,190

$ 3,195,000

$ 1,633,159

$ 3,287,242

$ -

$ 792,000

$ 1,266,411

$ 206,000

$ 101,500

$ -

$ 1,584,920

$ -

$ 2,500,000

$ 325,000

$ -

$ 1,967,360

$ -

2 of 5 550MW Super PC Cost Estimate - Greenfield.xls

Burns McDonnell

Confidential

EPRI/CPS - 550 MW Supercritical PC Cost Estimate Summary - 100% PRB

200

201

202

203

204

205

206

210

211

212

213

214

215

216

220

221

222

223

290

291

299

2301

2310

231

232

260

2401

2402

2403

2404

2405

2406

2407

2408

Material

Account /

Contract

Description

Dollars

CONSTRUCTION

Major Equipment Erection

Combustion Turbine Generator Erection

Steam Turbine - Generator Erection

Steam Generator / HRSG Erection

FGD System Erection

Particulate Removal (Baghouse or Precip) Erection

SCR / CO Catalyst Erection

Chimney

Civil / Structural Construction

Site Preparation

Piling

Substructures

Underground Utilities

Yard Structures

Foundations

Railroad

Structural Steel

Power Plant Structures

Pre-engineered Buildings

Sanitary Drains / Treatment

Final Painting

Final Paving, Landscaping & Cleanup

Demolition

Mechanical Construction

Misc Mechanical Equipment Erection

Below Grade Piping

Above Grade Piping

Insulation and Lagging

Field Erected Tanks

3,208,315

10,409,116

1,172,632

12,544,401

520,000

886,405

457,718

19,432,376

781,708

Electrical Construction

Electrical Equipment Erection

Wire / Cable

Grounding

Raceway

Lighting

Heat Tracing

Instrumentation

6,627,351

345,613

1,788,353

311,520

700,000

Switchyard -

Labor

Subcontract Subcontract

Dollars

4,091,681

15,065,704

20,694,597

2,286,786

8,614,204

546,580

104,192

6,883,668

2,854,928

27,741,082

5,410,223

3,117,057

17,426,660

944,212

9,538,073

799,429

470,570

682,463

Manhours

83,105

335,390

491,846

47,801

180,063

9,945

2,320

131,127

52,729

504,760

116,243

63,342

354,129

19,187

193,824

16,245

9,563

13,868

Indirect $

2,028,498

1,827,402

3,110,371

345,942

2,115,861

106,658

99,060

3,200,676

1,287,064

12,320,685

2,837,370

997,458

7,697,284

412,744

3,624,456

355,504

374,582

218,388

Dollars

720,000

164,368,421

15,000,000

40,392,509

10,000,000

10,040,500

70,000

10,556,140

1,500,000

435,928

600,000

1,499,100

83,100

4,840,000

Total

Dollars

$ -

$ 6,840,179

$ 164,368,421

$ -

$ 15,000,000

$ -

$ 60,493,929

$ 10,000,000

$ -

$ 34,214,084

$ 10,040,500

$ 3,875,360

$ 33,830,606

$ -

$ 2,673,238

$ 1,525,585

$ -

$ 10,684,344

$ 4,599,709

$ 59,494,143

$ 9,029,301

$ 1,499,100

$ -

$ 4,197,616

$ 31,751,294

$ 1,702,569

$ 14,950,883

$ 1,466,452

$ 1,545,152

$ 900,852

$ 4,840,000

$ -

3 of 5 550MW Super PC Cost Estimate - Greenfield.xls

Burns McDonnell

Confidential

Account /

Contract

Description

5000

5001

5002

5003

5004

5005

5006

5007

5008

5009

5010

5011

5050

5051

5052

5053

5054

5055

5056

5057

5058

5059

5060

EPC CONTRACTOR INDIRECT COSTS

Construction Indirects

Construction Management

Field Office Expense

Temporary Facilities

Temporary Utilities

Construction Equipment / Operators

Heavy Haul

Small Tools & Consumables

Site Services

Construction Testing

Preoperational Testing, Startup, & Calibration

Safety

Miscellaneous Construction Indirects

Project Indirects

Site Surveys/Studies

Performance Testing

Project Management & Engineering

Training

Operating Spare Parts

Project Insurance

Project Bonds

Escalation

Sales Tax

EPC Contingency

EPC Fee

TOTAL EPC PROJECT COST

EPRI/CPS - 550 MW Supercritical PC Cost Estimate Summary - 100% PRB

Material

Dollars

Labor

Manhours

Dollars

Subcontract Subcontract

Dollars Indirect $

24,712,644

2,754,590

1,250,000

500,000

8,786,000

700,000

300,000

38,115,000

225,000

2,408,182

46,431,601

97,506,363

Total

Dollars

$ -

$ 24,712,644

$ -

$ 2,754,590

$ -

$ 1,250,000

$ -

$ 500,000

$ 8,786,000

$ -

$ 700,000

$ 300,000

$ 38,115,000

$ 225,000

$ -

$ 2,408,182

$ -

$ 46,431,601

$ 97,506,363

359,513,804 2,625,486 127,272,110 542,824,078 42,960,002 1,072,569,994

4 of 5 550MW Super PC Cost Estimate - Greenfield.xls

Burns McDonnell

Confidential

EPRI/CPS - 550 MW Supercritical PC Cost Estimate Summary - 100% PRB

6008

6009

6010

6011

6012

6013

6014

6015

6000

6001

6002

6003

6004

6005

6006

6007

6016

6017

6018

6019

6020

6021

6022

Material

Account /

Contract

Description

Owner Indirects

Project Development

Owner Operations Personnel

Owners OE

Owners Legal Council

Owner Startup Engineering

Permitting & License Fees

Land

Water Rights

Political Concessions / Area Development Fees / Labor Camps

Startup/Testing

Initial Fuel Inventory

Site Surveys/Studies

Site Security

Transmission Interconnection / Upgrades

Operating Spare Parts

Permanent Plant Equipment & Furnishings

Builder's Risk Insurance

Escalation Owner's Indirects

Sales Tax & Duties

Owner Contingency

Financing Fees

Interest During Construction

Dollars

5,752,221

5,780,000

Manhours

Labor

Dollars

Subcontract

Dollars

2,000,000

7,200,000

20,000,000

2,000,000

2,910,000

7,500,000

1,000,000

1,114,760

10,692,000

1,728,000

4,826,565

57,253,677

Subcontract

Indirect $

Total

Dollars

$ -

$ 2,000,000

$ 7,200,000

$ 20,000,000

$ 2,000,000

$ -

$ 2,910,000

$ 7,500,000

$ -

$ 1,000,000

$ 1,114,760

$ 10,692,000

$ -

$ 1,728,000

$ -

$ 5,752,221

$ 5,780,000

$ 4,826,565

$ -

$ 57,253,677

$ -

TOTAL OWNER COST

TOTAL EPC PROJECT COST

TOTAL OWNER'S COST

PROJECT TOTAL

11,532,221 118,225,002 129,757,223

$ 359,513,804

$ 11,532,221

2,625,486

$ 127,272,110

$ -

$ 542,824,078

$ 118,225,002

$ 42,960,002

$ -

$ 1,072,569,994

$ 129,757,223

$ 371,046,025 2,625,486 $ 127,272,110 $ 661,049,080 $ 42,960,002 $ 1,202,327,217

5 of 5 550MW Super PC Cost Estimate - Greenfield.xls

HEAT BALANCE DIAGRAMS

F-1

LEGEND

M- Mass Flow, pph

T- Temperature, F

P- Pressure, psia

H- Enthalpy, Btu/lb

SYNGAS

Fuel Gas

Heater

405 T

COMP

TURB

COMPONENTS IN THE HRSG BELOW DO NOT REPRESENT THE

ACTUAL LAYOUT OF THE HRSG. ARRANGEMENT IS SCHEMATIC ONLY.

D C B

B A

279 T

FROM HRSG 2

716,664

1,030

1,903

1,497

1,652,990

1,026

575

1,533

HPST IPST

672,307

724

634

1,363

TO HRSG 2

Stream

IGCC Process Requirements

SRU and TGTU LP Steam Production

Hg Removal Preheater & Diluent N

Heater

Syngas Cooler and SRU IP Steam Production

TGTU HP Steam Requirements

Selexol and ASU IP Steam

ASU, Selexol, Sour Water Reboiler Water

Consumption

HCN Hydrolysis Preheater and Saturator Pump

Around Heater

Flow Out (lb/hr)

1,223

160,767

494,039

1,272

58,872

26,370

312,172

4,381

630

109

655

Process Duty

(MMBtu/hr)

1.11

14.25

404.1

2.05

52.1

25.4

97.4

358,332

1,038

2,001

1,499

826,495

1,031

588

1,535

LPST

1630276 M

90 T

1.42 in HgA

1559 MMBTU/hr

FROM HRSG 2

Aux Cooling Water Return

70,866,496

COOLING TOWER 2267 MMBTU/hr

70,866,496

Aux Cooling Water Supply

BFP

E F

GSC

ST LEAKS

TO HRSG 2

Syngas Condensing

& GTG Air Cooling

205 MMBTU/hr

1,800,033

213

182

PERFORMANCE SUMMARY

DRY BULB TEMP, °F

WET BULB TEMP, °F

RELATIVE HUMIDITY, %

ELEVATION, FT

GTG1 OUTPUT, kW

GTG2 OUTPUT, kW

STG OUTPUT, kW

GROSS PLANT OUTPUT, kW

POWER BLOCK AUX LOAD, kW

GASIFICATION BLOCK AUX POWER, kW

TOTAL AUX POWER, kW

GTG1 HEAT RATE, BTU/kWh (HHV)

GTG1 HEAT CONS, MMBTU/h (HHV)

GTG2 HEAT RATE, BTU/kWh (HHV)

GTG2 HEAT CONS, MMBTU/h (HHV)

TOTAL COAL HEAT INPUT, MMBtu/h (HHV)

NET PLANT OUTPUT, kW

NET PLANT HEAT RATE, BTU/kWh (HHV)

NET CYCLE EFFICIENCY

EPRI / CPS Energy

2x1 7FB IGCC - Shell Gasification Process

BMCD PROJECT 42127

DATE

7/21/2006

HEAT BALANCE DIAGRAM

100% PRB @ 43DB

DESIGNED: J. SCHWARZ

MODEL REV.

78%

100

9,369

2,174

9,369

2,174

5,444

599,224

9,085

38%

232,009

272,581

736,599

22,465

114,911

137,376

LEGEND

M- Mass Flow, pph

T- Temperature, F

P- Pressure, psia

H- Enthalpy, Btu/lb

SYNGAS

Fuel Gas

Heater

405 T

COMP

TURB

COMPONENTS IN THE HRSG BELOW DO NOT REPRESENT THE

ACTUAL LAYOUT OF THE HRSG. ARRANGEMENT IS SCHEMATIC ONLY.

D C B

B A

245 T

FROM HRSG 2

710,964

1,053

1,904

1,511

1,562,644

1,053

550

1,548

HPST IPST

667,745

732

607

1,369

TO HRSG 2

Stream

IGCC Process Requirements

SRU and TGTU LP Steam Production

Hg Removal Preheater & Diluent N

Heater

Syngas Cooler and SRU IP Steam Production

TGTU HP Steam Requirements

Selexol and ASU IP Steam

ASU, Selexol, Sour Water Reboiler Water

Consumption

HCN Hydrolysis Preheater and Saturator Pump

Around Heater

Flow Out (lb/hr)

1,118

151,738

452,803

1,192

55,337

26,370

296,062

1,118

653

655

Process Duty

(MMBtu/hr)

1.04

13.35

378.2

1.91

50.1

25.4

91.3

355,475

1,060

2,003

1,513

781,322

1,058

562

1,551

LPST

1536088 M

104 T

2.18 in HgA

1471 MMBTU/hr

FROM HRSG 2

Aux Cooling Water Return

70,866,496

COOLING TOWER 2130 MMBTU/hr

70,866,496

Aux Cooling Water Supply

BFP

E F

GSC

ST LEAKS

TO HRSG 2

Syngas Condensing

& GTG Air Cooling

91 MMBTU/hr

1,698,067

165

133

PERFORMANCE SUMMARY

DRY BULB TEMP, °F

WET BULB TEMP, °F

RELATIVE HUMIDITY, %

ELEVATION, FT

GTG1 OUTPUT, kW

GTG2 OUTPUT, kW

STG OUTPUT, kW

GROSS PLANT OUTPUT, kW

POWER BLOCK AUX LOAD, kW

GASIFICATION BLOCK AUX POWER, kW

TOTAL AUX POWER, kW

GTG1 HEAT RATE, BTU/kWh (HHV)

GTG1 HEAT CONS, MMBTU/h (HHV)

GTG2 HEAT RATE, BTU/kWh (HHV)

GTG2 HEAT CONS, MMBTU/h (HHV)

TOTAL COAL HEAT INPUT, MMBtu/h (HHV)

NET PLANT OUTPUT, kW

NET PLANT HEAT RATE, BTU/kWh (HHV)

NET CYCLE EFFICIENCY

EPRI / CPS Energy

2x1 7FB IGCC - Shell Gasification Process

BMCD PROJECT 42127

DATE

7/21/2006

HEAT BALANCE DIAGRAM

100% PRB @ 73DB

DESIGNED: J. SCHWARZ

MODEL REV.

82%

100

9,057

2,037

9,057

2,037

5,100

553,059

9,222

37%

224,869

260,134

709,872

21,952

134,861

156,813

LEGEND

M- Mass Flow, pph

T- Temperature, F

P- Pressure, psia

H- Enthalpy, Btu/lb

SYNGAS

Fuel Gas

Heater

405 T

COMP

TURB

COMPONENTS IN THE HRSG BELOW DO NOT REPRESENT THE

ACTUAL LAYOUT OF THE HRSG. ARRANGEMENT IS SCHEMATIC ONLY.

D C B

B A

247 T

FROM HRSG 2

691,351

1,050

1,853

1,511

1,531,861

1,052

539

1,548

HPST IPST

649,198

731

594

1,369

TO HRSG 2

Stream

IGCC Process Requirements

SRU and TGTU LP Steam Production

Hg Removal Preheater & Diluent N

Heater

Syngas Cooler and SRU IP Steam Production

TGTU HP Steam Requirements

Selexol and ASU IP Steam

ASU, Selexol, Sour Water Reboiler Water

Consumption

HCN Hydrolysis Preheater and Saturator Pump

Around Heater

Flow Out (lb/hr)

1,087

146,920

438,696

1,154

53,707

26,370

291,102

1,087

649

650

Process Duty

(MMBtu/hr)

1.01

12.93

366.3

1.86

48.7

25.4

88.4

345,697

1,057

1,948

1,512

765,930

1,056

551

1,550

LPST

1505624 M

109 T

2.53 in HgA

1448 MMBTU/hr

FROM HRSG 2

Aux Cooling Water Return

70,866,496

COOLING TOWER 2156 MMBTU/hr

70,866,496

Aux Cooling Water Supply

BFP

E F

GSC

ST LEAKS

TO HRSG 2

Syngas Condensing

& GTG Air Cooling

88 MMBTU/hr

1,663,191

169

137

PERFORMANCE SUMMARY

DRY BULB TEMP, °F

WET BULB TEMP, °F

RELATIVE HUMIDITY, %

ELEVATION, FT

GTG1 OUTPUT, kW

GTG2 OUTPUT, kW

STG OUTPUT, kW

GROSS PLANT OUTPUT, kW

POWER BLOCK AUX LOAD, kW

GASIFICATION BLOCK AUX POWER, kW

TOTAL AUX POWER, kW

GTG1 HEAT RATE, BTU/kWh (HHV)

GTG1 HEAT CONS, MMBTU/h (HHV)

GTG2 HEAT RATE, BTU/kWh (HHV)

GTG2 HEAT CONS, MMBTU/h (HHV)

TOTAL COAL HEAT INPUT, MMBtu/h (HHV)

NET PLANT OUTPUT, kW

NET PLANT HEAT RATE, BTU/kWh (HHV)

NET CYCLE EFFICIENCY

EPRI / CPS Energy

2x1 7FB IGCC - Shell Gasification Process

BMCD PROJECT 42127

DATE

7/21/2006

HEAT BALANCE DIAGRAM

100% PRB @ 93DB

DESIGNED: J. SCHWARZ

MODEL REV.

49%

100

9,149

1,972

9,149

1,972

4,940

528,398

9,348

37%

215,584

250,374

681,542

21,763

131,381

153,144

LEGEND

M- Mass Flow, pph

T- Temperature, F

P- Pressure, psia

H- Enthalpy, Btu/lb

SYNGAS

Fuel Gas

Heater

405 T

COMP

TURB

COMPONENTS IN THE HRSG BELOW DO NOT REPRESENT THE

ACTUAL LAYOUT OF THE HRSG. ARRANGEMENT IS SCHEMATIC ONLY.

D C B

B A

267 T

FROM HRSG 2

701,666

1,031

1,903

1,497

1,632,862

1,030

570

1,535

HPST IPST

657,519

721

627

1,362

TO HRSG 2

Stream

IGCC Process Requirements

SRU and TGTU LP Steam Production

Hg Removal Preheater & Diluent N

Heater

Syngas Cooler and SRU IP Steam Production

TGTU HP Steam Requirements

Selexol and ASU IP Steam

ASU, Selexol, Sour Water Reboiler Water

Consumption

HCN Hydrolysis Preheater and Saturator Pump

Around Heater

Flow Out (lb/hr)

6,007

161,899

501,323

4,175

95,654

26,370

311,661

27,822

493

652

Process Duty

(MMBtu/hr)

5.52

14.25

417.9

6.71

86.0

25.4

96.5

350,827

1,038

2,002

1,499

816,431

1,034

582

1,537

LPST

1624996 M

89 T

1.37 in HgA

1556 MMBTU/hr

FROM HRSG 2

Aux Cooling Water Return

70,866,496

COOLING TOWER 2186 MMBTU/hr

70,866,496

Aux Cooling Water Supply

BFP

E F

GSC

ST LEAKS

TO HRSG 2

Syngas Condensing

& GTG Air Cooling

196 MMBTU/hr

1,848,329

208

177

PERFORMANCE SUMMARY

DRY BULB TEMP, °F

WET BULB TEMP, °F

RELATIVE HUMIDITY, %

ELEVATION, FT

GTG1 OUTPUT, kW

GTG2 OUTPUT, kW

STG OUTPUT, kW

GROSS PLANT OUTPUT, kW

POWER BLOCK AUX LOAD, kW

GASIFICATION BLOCK AUX POWER, kW

TOTAL AUX POWER, kW

GTG1 HEAT RATE, BTU/kWh (HHV)

GTG1 HEAT CONS, MMBTU/h (HHV)

GTG2 HEAT RATE, BTU/kWh (HHV)

GTG2 HEAT CONS, MMBTU/h (HHV)

TOTAL COAL HEAT INPUT, MMBtu/h (HHV)

NET PLANT OUTPUT, kW

NET PLANT HEAT RATE, BTU/kWh (HHV)

NET CYCLE EFFICIENCY

EPRI / CPS Energy

2x1 7FB IGCC - Shell Gasification Process

BMCD PROJECT 42127

DATE

7/21/2006

HEAT BALANCE DIAGRAM

50% PRB 50% PET COKE @ 43DB

DESIGNED: J. SCHWARZ

MODEL REV.

78%

100

9,319

2,162

9,319

2,162

5,341

596,993

8,946

38%

232,018

270,141

734,177

22,026

115,159

137,185

LEGEND

M- Mass Flow, pph

T- Temperature, F

P- Pressure, psia

H- Enthalpy, Btu/lb

SYNGAS

Fuel Gas

Heater

405 T

COMP

TURB

COMPONENTS IN THE HRSG BELOW DO NOT REPRESENT THE

ACTUAL LAYOUT OF THE HRSG. ARRANGEMENT IS SCHEMATIC ONLY.

D C B

B A

237 T

FROM HRSG 2

698,492

1,053

1,904

1,511

1,552,656

1,057

550

1,550

HPST IPST

655,324

731

605

1,369

TO HRSG 2

Stream

IGCC Process Requirements

SRU and TGTU LP Steam Production

Hg Removal Preheater & Diluent N

Heater

Syngas Cooler and SRU IP Steam Production

TGTU HP Steam Requirements

Selexol and ASU IP Steam

ASU, Selexol, Sour Water Reboiler Water

Consumption

HCN Hydrolysis Preheater and Saturator Pump

Around Heater

Flow Out (lb/hr)

5,512

152,890

462,743

3,921

90,058

26,370

296,225

18,499

537

652

Process Duty

(MMBtu/hr)

5.18

13.38

392.5

6.28

81.4

25.4

90.7

349,246

1,061

2,004

1,513

776,328

1,061

561

1,552

LPST

1531101 M

104 T

2.18 in HgA

1467 MMBTU/hr

FROM HRSG 2

Aux Cooling Water Return

70,866,496

COOLING TOWER 2164 MMBTU/hr

70,866,496

Aux Cooling Water Supply

BFP

E F

GSC

ST LEAKS

TO HRSG 2

Syngas Condensing

& GTG Air Cooling

83 MMBTU/hr

1,741,828

163

131

PERFORMANCE SUMMARY

DRY BULB TEMP, °F

WET BULB TEMP, °F

RELATIVE HUMIDITY, %

ELEVATION, FT

GTG1 OUTPUT, kW

GTG2 OUTPUT, kW

STG OUTPUT, kW

GROSS PLANT OUTPUT, kW

POWER BLOCK AUX LOAD, kW

GASIFICATION BLOCK AUX POWER, kW

TOTAL AUX POWER, kW

GTG1 HEAT RATE, BTU/kWh (HHV)

GTG1 HEAT CONS, MMBTU/h (HHV)

GTG2 HEAT RATE, BTU/kWh (HHV)

GTG2 HEAT CONS, MMBTU/h (HHV)

TOTAL COAL HEAT INPUT, MMBtu/h (HHV)

NET PLANT OUTPUT, kW

NET PLANT HEAT RATE, BTU/kWh (HHV)

NET CYCLE EFFICIENCY

EPRI / CPS Energy

2x1 7FB IGCC - Shell Gasification Process

BMCD PROJECT 42127

DATE

7/21/2006

HEAT BALANCE DIAGRAM

50% PRB 50% PET COKE @ 73DB

DESIGNED: J. SCHWARZ

MODEL REV.

82%

100

8,971

2,030

8,971

2,030

5,016

553,022

9,070

38%

226,335

258,397

711,067

21,867

136,178

158,045

LEGEND

M- Mass Flow, pph

T- Temperature, F

P- Pressure, psia

H- Enthalpy, Btu/lb

SYNGAS

Fuel Gas

Heater

405 T

COMP

TURB

COMPONENTS IN THE HRSG BELOW DO NOT REPRESENT THE

ACTUAL LAYOUT OF THE HRSG. ARRANGEMENT IS SCHEMATIC ONLY.

D C B

B A

238 T

FROM HRSG 2

672,327

1,050

1,835

1,511

1,527,907

1,052

540

1,548

HPST IPST

630,470

733

593

1,371

TO HRSG 2

Stream

IGCC Process Requirements

SRU and TGTU LP Steam Production

Hg Removal Preheater & Diluent N

Heater

Syngas Cooler and SRU IP Steam Production

TGTU HP Steam Requirements

Selexol and ASU IP Steam

ASU, Selexol, Sour Water Reboiler Water

Consumption

HCN Hydrolysis Preheater and Saturator Pump

Around Heater

Flow Out (lb/hr)

5,355

148,275

449,026

3,802

87,441

26,370

292,901

18,876

527

646

Process Duty

(MMBtu/hr)

5.03

12.98

380.6

6.12

79.1

25.4

87.9

336,158

1,057

1,932

1,513

763,953

1,056

551

1,550

LPST

1508008 M

109 T

2.52 in HgA

1450 MMBTU/hr

FROM HRSG 2

Aux Cooling Water Return

70,866,496

COOLING TOWER 2195 MMBTU/hr

70,866,496

Aux Cooling Water Supply

BFP

E F

GSC

ST LEAKS

TO HRSG 2

Syngas Condensing

& GTG Air Cooling

80 MMBTU/hr

1,713,230

166

135

PERFORMANCE SUMMARY

DRY BULB TEMP, °F

WET BULB TEMP, °F

RELATIVE HUMIDITY, %

ELEVATION, FT

GTG1 OUTPUT, kW

GTG2 OUTPUT, kW

STG OUTPUT, kW

GROSS PLANT OUTPUT, kW

POWER BLOCK AUX LOAD, kW

GASIFICATION BLOCK AUX POWER, kW

TOTAL AUX POWER, kW

GTG1 HEAT RATE, BTU/kWh (HHV)

GTG1 HEAT CONS, MMBTU/h (HHV)

GTG2 HEAT RATE, BTU/kWh (HHV)

GTG2 HEAT CONS, MMBTU/h (HHV)

TOTAL COAL HEAT INPUT, MMBtu/h (HHV)

NET PLANT OUTPUT, kW

NET PLANT HEAT RATE, BTU/kWh (HHV)

NET CYCLE EFFICIENCY

EPRI / CPS Energy

2x1 7FB IGCC - Shell Gasification Process

BMCD PROJECT 42127

DATE

7/21/2006

HEAT BALANCE DIAGRAM

50% PRB 50% PET COKE @ 93DB

DESIGNED: J. SCHWARZ

MODEL REV.

49%

100

9,075

1,969

9,075

1,969

4,864

528,165

9,209

37%

216,963

248,701

682,628

21,649

132,813

154,462

O&M COST DETAIL

G-1

IGCC O&M.XLS Rev 3 1/28/05

Operating Assumptions

Greenfield \ Brownfield

Basis Year

Plant Capacity Factor

Hours per Year

Number of Gasifiers

Number of Steam Turbines

Boiler Output, (Net kW Each)

Normal Operation

Gross Gas Turbine Output, kW (Each)

Gross Steam Turbine Output, kW (Each)

Auxiliary Load, %

Margin, %

Net Unit Output, kW

Net Unit Heat Rate, Btu/kWh

Unit Fuel Consumption, MMBtu/hr

Net Facility Output, kW (Avg Ambient Conditions)

Net Facility Heat Rate, Btu/kWh

Net Annual Output, MWh (Total Facility)

Annual Fuel Consumption, MMBtu (Total Facility)

Coal Type

Boiler Technology

Type of Boiler

Type of Feedwater Pump Drive

Type of NOx Control

Type of SO2 Control

Type of Particulate Control

Type of Mercury Control

Cooling Tower Materials of Construction

Type of Sidestream Treatment

Fly Ash Disposal

Slag Disposal

EPRI / CPS Energy

2x1 7FB IGCC

Operations and Maintenance Estimates

BMcD Project: 42127

2x1 7FB IGCC - 100% PRB

Greenfield

2006

85.0%

7446

250,000

2x1 7FB IGCC - 50% PRB / 50%

Pet Coke

Greenfield

2006

85.0%

7446

250,000

224,869

260,134

22.09%

0.00%

553,072

9,220

5,100

226,335

258,397

22.23%

0.00%

553,022

9,069

5,015

553,072

9,220

553,022

9,069

4,118,174

37,971,622

4,117,804

37,343,289

EPRI UDBS PRB 50% PRB / 50% Pet Coke (by wt%)

IGCC

Subcritical

Motor

N2 Injection

Selexol

N/A

IGCC

Subcritical

Motor

N2 Injection

Selexol

N/A

Carbon Bed

Fiberglass

None

Landfill

Carbon Bed

Fiberglass

None

Landfill

Page 1 of 6 BURNS MCDONNELL

IGCC O&M.XLS Rev 3 1/28/05

Operating Assumptions

Fixed O&M

Labor

# of People

Average Salary

Total Labor

Office & Admin

Other Fixed O&M

Employee Expenses \ Training

Contract Labor

Environmental Expenses

Safety Expenses

Buildings, Grounds, and Painting

Other Supplies & Expenses

Communication

Control Room \ Lab Expenses

Annual Steam Turbine Inspections

Annual Gasifier Inspections

Annual Syngas Cooling and Treatment Inspections

Start-up power demand charge

$/kW-Mo kW

Water supply demand charge

$/acre-ft acre-ft

Water discharge demand charge

$/acre-ft acre-ft

Standby Power Energy Costs

$/kWh kWh

Standby Power Service Fee

$/Month

Months

Property Taxes & Insurance

Total Fixed O&M Annual Cost

EPRI / CPS Energy

2x1 7FB IGCC

Operations and Maintenance Estimates

BMcD Project: 42127

2x1 7FB IGCC - 100% PRB

2x1 7FB IGCC - 50% PRB / 50%

Pet Coke

126 People

$93,934/ Person

$ 11,835,700

126 People

$93,934/ Person

$ 11,835,700

$ 118,400

$ 1,479,500

$ 118,400

$ 1,479,500

$ 100,000

$ 200,000

$ 100,000

$ 200,000

$ -

8,000

$ -

8,000

$ $ -

6,832

$ -

7,172

$ -

1,581 1,632

$ 98,600 $ 98,600

3,942,000

$ -

3,942,000

$ -

By Owner

$ 13,932,200

By Owner

Page 2 of 6 BURNS MCDONNELL

IGCC O&M.XLS Rev 3 1/28/05

EPRI / CPS Energy

2x1 7FB IGCC

Operations and Maintenance Estimates

BMcD Project: 42127

2x1 7FB IGCC - 100% PRB

2x1 7FB IGCC - 50% PRB / 50%

Pet Coke Operating Assumptions

Emissions Allowance Costs - Included in Variable O&M

Emissions Rates

NOx , lb/MMBtu

SOx , lb/MMBtu

CO2, lb/MMBtu

HG, lb/MMBtu

Emissions - TPY

NOx , TPY

SOx , TPY

CO2, TPY

HG, lb/year

Emissions Allowance Costs

NOx Allowance, $/ton-yr

SOx Allowance, $/ton-yr

CO2 Allowance, $/ton-yr

HG Allowance, $/lb-yr

Total Emissions Allowance Costs, $/yr

NOx Allowance Cost

SOx Allowance Cost

CO2 Allowance Cost

HG Allowance Cost

Total Annual Emissions Allowance Costs

0.063

0.019

215

7.769E-07

0.062

0.023

213

4.962E-07

1,196

361

4,086,517

29.50

1,158

429

3,980,767

18.53

$3,000

$1,000

$20,000

$3,000

$1,000

$20,000

$ 3,588,300

$ 360,700

$ -

$ 590,000

$ 4,539,000

$ 3,472,900

$ 429,400

$ -

$ 370,600

Page 3 of 6 BURNS MCDONNELL

IGCC O&M.XLS Rev 3 1/28/05

Operating Assumptions

Major Maintenance Costs - Included in Variable O&M

Steam Turbine / Generator Overhaul

Operating Hours

$/Turbine Hour

HRSG Major Replacements

$/Boiler - Yr

# of Boilers

Gasifier Major Replacements

$/Replacement

Replacement Interval, years

Candle Filter Major Replacements

$/Replacement

Replacement Interval, years

Gas Turbine Major Replacements

$/Replacement

$/Gas Turbine Hour

Syngas Treatment Major Replacements

$/Replacement

Replacement Interval, years

Air Separation Unit

$/Replacement

Replacement Interval, years

Mercury Carbon Bed Replacements

$/Replacement

Replacement Interval, years

COS Hydrolysis Catalyst

$/Catalyst

Catalyst Life, years

HCN Hydrolysis Catalyst

$/Catalyst

Catalyst Life, years

Shift Catalyst

$/Catalyst

Catalyst Life, years

Demin Water Treatment System Replacements

Total Annual Major Maintenance Costs

EPRI / CPS Energy

2x1 7FB IGCC

Operations and Maintenance Estimates

BMcD Project: 42127

2x1 7FB IGCC - 100% PRB

2x1 7FB IGCC - 50% PRB / 50%

Pet Coke

$ 260,400

7446

$ 35

$ 260,400

7446

$ 35

$ 200,000

$100,000

$ 200,000

$100,000

$ 885,800

$885,765

$ 765,900

$765,893

$ 300,000

$1,500,000

$ 300,000

$1,500,000

$ 8,148,685

$885,765

547

$ 8,148,685

$765,893

547

$ 375,000

$375,000

$ 395,000

$395,000

$ 275,000

$275,000

$ 275,000

$275,000

$ 530,300

$1,060,666

$ 530,300

$1,060,666

$ 320,000

$960,000

$ 320,000

$960,000

$ 320,000

$960,000

$ 320,000

$960,000

$ -

$ 3,600 $ 3,600

$ 11,618,785

Page 4 of 6 BURNS MCDONNELL

IGCC O&M.XLS Rev 3 1/28/05

EPRI / CPS Energy

2x1 7FB IGCC

Operations and Maintenance Estimates

BMcD Project: 42127

2x1 7FB IGCC - 100% PRB

2x1 7FB IGCC - 50% PRB / 50%

Pet Coke Operating Assumptions

Other Variable O&M

Water Consumption, MMGal/yr

Raw Water Makeup, MMGal/yr

Raw Water Makeup Treatment, MMGal/yr

Zero Liquid Discharge Treatment, MMGal/yr

Potable Water, MMGal/yr

Wastewater Discharge, MMGal/yr

Cooling Tower Makeup, MMGal/yr

Demin Water Makeup Treatment, MMGal/yr

Boiler Treatment Makeup Treatment, MMGal/yr

Water Consumable \ Treatment Costs, $/kGal

Raw Water, $/kGal

Raw Water Makeup Treatment, $/kGal

Zero Liquid Discharge Treatment, $/kGal

Potable Water, $/kGal

Wastewater Discharge, $/kGal

Cooling Tower Makeup, $/kGal

Demin Water Treatment, $/kGal

Boiler Treatment Chemicals, $/kGal

Total Water Related Costs

Raw Water

Raw Water Make-up Treatment

Zero Liquid Discharge Treatment Chemicals

Potable Water

Water Discharge

Cooling Tower Treatment Chemicals

Demin Water Treatment

Boiler Treatment Chemicals

Maintenance & Consumables (lube oil, nitrogen, hydrogen, etc.)

ZLD System General Maintenance

Membrane Replacements, $/yr

General Maintenance, $/yr

Water Treatment System General Maintenance, $/yr

Cooling Tower System General Maintenance, $/unit-yr

Other Variable O&M (Electronics, Controls, BOP Electrical, Steam Generators, Misc.)

2,226

515.11

2,100

$0.04

$0.01

$0.00

$1.00

$0.05

$0.55

$1.05

$7.4500

$ 92,000

$ 11,100

$ -

$ 1,500

$ 25,800

$ 1,159,300

$ 39,700

$ 149,700

$ 96,500

$ 11,700

$ -

$ 1,500

$ 26,600

$ 1,198,000

$ 39,700

$ 149,700

$0.04

$0.01

$0.00

$1.00

$0.05

$0.55

$1.05

$7.4500

2,337

531.64

2,170

$60,100

$45,100

$5,192,238

$60,100

$44,800

$5,250,717

Page 5 of 6 BURNS MCDONNELL

IGCC O&M.XLS Rev 3 1/28/05

Operating Assumptions

Other Variable O&M - (Cont.)

Consumable Consumption \ Disposal Rates

SCR Ammonia (Anhydrous), TPY

Sulfur, TPY

Fly Ash / Slag Sales, TPY

Fly Ash / Slag Disposal, TPY

Consumable \ Disposal Unit Costs

SCR Ammonia (Anhydrous), $/ton

Sulfur, $/ton

Fly Ash / Slag Sales, $/ton

Fly Ash / Slag Disposal, $/ton

Total Consumable \ Disposal Costs

SCR Ammonia (Anhydrous)

Sulfur Sales / Disposal

Fly Ash / Slag Sales

Fly Ash / Slag Disposal

Total Other Variable O&M

Total Fixed O&M Cost

$/year

$/kW-yr

Total Variable O&M Cost

$/year

$/MWh

EPRI / CPS Energy

2x1 7FB IGCC

Operations and Maintenance Estimates

BMcD Project: 42127

2x1 7FB IGCC - 100% PRB

2x1 7FB IGCC - 50% PRB / 50%

Pet Coke

8,390

138,213

$657.89

$0.00

$11.29

$ -

$ 1,560,200

$ -

$ 642,100

$ 8,336,738

58,728

56,884

$657.89

$0.00

$11.29

$ 13,932,200

$ 25.19

$ 13,932,200

$ 25.19

$ 24,494,523

$ 5.95

$ 23,313,202

$ 5.66

Page 6 of 6 BURNS MCDONNELL

PC Unit O&M_r1 (working).XLS Rev 3 1/28/05

Operating Assumptions

Greenfield \ Brownfield

Basis Year

Plant Capacity Factor

Hours per Year

Number of Boilers

Number of Steam Turbines

Boiler Output, (Net kW Each)

Steam Turbine Output, (Net kW Each)

Net Facility Output, kW

Normal Operation

Gross Steam Turbine Output, kW (Each)

Gross Steam Turbine Heat Rate

Auxiliary Load, %

Margin, %

Net Unit Output, kW

Net Unit Heat Rate, Btu/kWh

Unit Fuel Consumption, MMBtu/hr

Net Facility Output, kW (Avg Ambient Conditions)

Net Facility Heat Rate, Btu/kWh

Net Annual Output, MWh (Total Facility)

Annual Fuel Consumption, MMBtu (Total Facility)

Coal Type

Boiler Technology

Type of Boiler

Type of Feedwater Pump Drive

Type of NOx Control

Type of SO2 Control

Type of Particulate Control

Type of Mercury Control

Cooling Tower Materials of Construction

Type of Sidestream Treatment

Fly Ash Disposal

Gypsum Disposal

Bottom Ash Disposal

EPRI / CPS Energy

550 MW Supercritical PC - 100% PRB

Operations and Maintenance Estimates

BMcD Project: 42127

550 PC-Wet Tower / Wet Scrubber - Greenfield

Greenfield

2006

85.0%

7446

550,000

614,525

6,986

10.50%

0.00%

550,000

9,149

5,032

550,000

9,149

4,095,300

37,468,109

EPRI UDBS PRB

Pulverized Coal

Supercritical

Motor

SCR

Wet

Fabric Filter

Fabric Filter / Wet Scrubber

Fiberglass

None

Landfill

Page 1 of 5 BURNS MCDONNELL

PC Unit O&M_r1 (working).XLS Rev 3 1/28/05

Operating Assumptions

Fixed O&M

Labor

# of People

Average Salary

Total Labor

Office & Admin

Other Fixed O&M

Employee Expenses \ Training

Contract Labor

Environmental Expenses

Safety Expenses

Buildings, Grounds, and Painting

Other Supplies & Expenses

Communication

Control Room \ Lab Expenses

Annual Steam Turbine Inspections

Annual Boiler Inspections

Annual APC Inspections

Start-up power demand charge

$/kW-Mo kW

Water supply demand charge

$/acre-ft acre-ft

Water discharge demand charge

$/acre-ft acre-ft

Standby Power Energy Costs

$/kWh kWh

Standby Power Service Fee

$/Month

Months

Property Taxes & Insurance

Total Fixed O&M Annual Cost

EPRI / CPS Energy

550 MW Supercritical PC - 100% PRB

Operations and Maintenance Estimates

BMcD Project: 42127

550 PC-Wet Tower / Wet Scrubber - Greenfield

103 People

$94,056/ Person

$ 9,687,800

$ 96,900

$ 1,211,000

$ 100,000

$ 80,000

$ 100,000

$ -

64,200

$ -

7,541

$ -

1,632

$ 98,600

0.025

3,942,000

$ -

By Owner

Page 2 of 5 BURNS MCDONNELL

PC Unit O&M_r1 (working).XLS Rev 3 1/28/05

EPRI / CPS Energy

550 MW Supercritical PC - 100% PRB

Operations and Maintenance Estimates

BMcD Project: 42127

Operating Assumptions

Emissions Allowance Costs - Included in Variable O&M

Emissions Rates

NOx , lb/MMBtu

SOx , lb/MMBtu

CO2, lb/MMBtu

HG, lb/MMBtu

Emissions - TPY

NOx , TPY

SOx , TPY

CO2, TPY

HG, lb/year

Emissions Allowance Costs

NOx Allowance, $/ton-yr

SOx Allowance, $/ton-yr

CO2 Allowance, $/ton-yr

HG Allowance, $/lb-yr

Total Emissions Allowance Costs, $/yr

NOx Allowance Cost

SOx Allowance Cost

CO2 Allowance Cost

HG Allowance Cost

Total Annual Emissions Allowance Costs

Major Maintenance Costs - Included in Variable O&M

Steam Turbine / Generator Overhaul

Operating Hours

$/Turbine Hour

Steam Generator Major Replacements

$/Boiler - Yr

# of Boilers

Baghouse Bag Replacement

$/Replacement

Replacement Interval, years

SCR Catalyst Replacement

$/Catalyst

Catalyst Life, years

Demin Water Treatment System Replacements

Total Annual Major Maintenance Costs

550 PC-Wet Tower / Wet Scrubber - Greenfield

0.050

0.060

213.5

2.315E-06

937

1,128

3,998,878

86.73

$3,000

$1,000

$20,000

$ 2,810,100

$ 1,127,900

$ -

$ 1,734,700

$ 339,200

7446

$ 46

$ 893,900

$893,900

$ 253,400

$1,266,900

$ 312,000

$936,100

$ 4,300

Page 3 of 5 BURNS MCDONNELL

PC Unit O&M_r1 (working).XLS Rev 3 1/28/05

EPRI / CPS Energy

550 MW Supercritical PC - 100% PRB

Operations and Maintenance Estimates

BMcD Project: 42127

Operating Assumptions

Other Variable O&M

Water Consumption, MMGal/yr

Raw Water Makeup, MMGal/yr

Raw Water Makeup Treatment, MMGal/yr

Zero Liquid Discharge Treatment, MMGal/yr

Potable Water, MMGal/yr

Wastewater Discharge, MMGal/yr

Cooling Tower Makeup, MMGal/yr

Demin Water Makeup Treatment, MMGal/yr

Boiler Treatment Makeup Treatment, MMGal/yr

Water Consumable \ Treatment Costs, $/kGal

Raw Water, $/kGal

Raw Water Makeup Treatment, $/kGal

Zero Liquid Discharge Treatment, $/kGal

Potable Water, $/kGal

Wastewater Discharge, $/kGal

Cooling Tower Makeup, $/kGal

Demin Water Treatment, $/kGal

Boiler Treatment Chemicals, $/kGal

Total Water Related Costs

Raw Water

Raw Water Make-up Treatment

Zero Liquid Discharge Treatment Chemicals

Potable Water

Water Discharge

Cooling Tower Treatment Chemicals

Demin Water Treatment

Boiler Treatment Chemicals

Maintenance & Consumables (lube oil, nitrogen, hydrogen, etc.)

ZLD System General Maintenance

Membrane Replacements, $/yr

General Maintenance, $/yr

SCR System General Maintenance

General Maintenance, $./unit-yr

Scrubber System General Maintenance

Absorber, Dewatering & Accessories, $/unit-yr

Limestone Preparation, $/yr

Water Treatment System General Maintenance, $/yr

Cooling Tower System General Maintenance, $/unit-yr

Other Variable O&M (Electronics, Controls, BOP Electrical, Steam Generators, Misc.)

550 PC-Wet Tower / Wet Scrubber - Greenfield

$ 101,500

$ 12,300

$ -

$ 1,500

$ 26,600

$ 1,393,400

$ 63,600

$ 160,600

$0.041

$0.005

$0.000

$1.000

$0.050

$0.642

$1.050

$3.730

2,457

532

2,170

$64,200

$120,700

$342,400

$59,800

$47,700

$5,000,000

Page 4 of 5 BURNS MCDONNELL

PC Unit O&M_r1 (working).XLS Rev 3 1/28/05

Operating Assumptions

Other Variable O&M - (Cont.)

Consumable Consumption \ Disposal Rates

Lime Consumption, TPY

Limestone Consumption, TPY

SCR Ammonia (Anhydrous), TPY

Halogenated Carbon Injection, TPY

Scrubber Sludge (Sales) / Disposal, TPY

Fly Ash Sales, TPY

Fly Ash Disposal, TPY

Bottom Ash (Sales) / Disposal, TPY

Consumable \ Disposal Unit Costs

Lime Consumption, $/ton

Limestone Consumption, $/ton

SCR Ammonia (Anhydrous), $/ton

Halogenated Carbon Injection, $/ton

Scrubber Sludge (Sales) / Disposal, $/ton

Fly Ash Sales, $/ton

Fly Ash Disposal, $/ton

Bottom Ash (Sales) / Disposal, $/ton

Total Consumable \ Disposal Costs

Lime Consumption

Limestone Consumption

SCR Ammonia (Anhydrous)

Halogenated Carbon Injection

Scrubber Sludge (Sales) / Disposal

Fly Ash Sales

Fly Ash Disposal

Bottom Ash (Sales) / Disposal

Total Other Variable O&M

Total Fixed O&M Cost

$/year

$/kW-yr

Total Variable O&M Cost

$/year

$/MWh

EPRI / CPS Energy

550 MW Supercritical PC - 100% PRB

Operations and Maintenance Estimates

BMcD Project: 42127

550 PC-Wet Tower / Wet Scrubber - Greenfield

29,150

1,584

56,228

125,137

31,172

$86.00

$18.00

$658

$1,545

$11.29

$0.00

$11.29

$ -

$ 524,700

$ 1,041,800

$ 634,700

$ -

$ 1,412,600

$ 351,900

$ 11,374,300

$ 20.68

$ 18,835,500

$ 4.60

Page 5 of 5 BURNS MCDONNELL

SYSTEM OF INTERNATIONAL UNITS CONVERSION

TABLE

The heat and material balances included in this report are shown in British (English) units. The following table can be used for conversion to SI units.

British Unit

P, absolute pressure, psia, multiply by 6.895 x10

-3

°F, temperature, (F minus 32) divided by 1.8

H, enthalpy, Btu/lb, multiply H by 2.3260

W, total mass flow, lb/h, multiply W by 0.4536

Heat rate, Btu/kWh, multiply Btu/kWh by 1.0551

Air emissions, lb/MMBtu, multiply by 429.9

Flow, gal/minute, multiply by 0.06309

= MPa (megapascals)

°C (Centigrade)

= kJ/kg (kilojoules/kilogram)

= kg/h (kilogram/hour)

= kJ/kWh (kilojoules/kilowatt-hour)

= kg/GJ (kilogram/gigajoule)

= l/s (liters/second)

H-1

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